Steam driven direct contact steam generation

ABSTRACT

The present invention is a system and method for steam production for oil production. The method includes generating steam, mixing the steam with water containing solids and organics, separating solids, and injecting the steam through an injection well or using it above ground for oil recovery, such as for generating hot process water. The system includes a steam drive direct contact steam generator. The water feed of the present invention can be hot produced water separated from a produced oil emulsion and/or low quality water salvaged from industrial plants, such as refineries and tailings from an oilsands mine.

RELATED U.S. APPLICATIONS

The present application is a continuation-in-part application under 35U.S. Code Section 120 of U.S. application Ser. No. 12/635,597, filed onDec. 10, 2009, and entitled “STEAM GENERATION PROCESS FOR ENHANCED OILRECOVERY”, presently pending. The present application also claimscontinuation-in-part priority from U.S. patent application Ser. No.12/636,729, filed on Dec. 12, 2009 and entitled “SYSTEM AND METHOD FORMINIMIZING THE NEGATIVE ENVIROMENTAL IMPACT OF THE OILSANDS INDUSTRY”.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

REFERENCE TO MICROFICHE APPENDIX

Not applicable.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This application relates to a system and method for producing steam froma contaminated water feed for Enhanced Oil Recovery (EOR). Thisinvention relates to processes for directly using steam energy,preferably superheated dry steam, for generating additional steam fromcontaminated water by direct contact, and using this produced steam forvarious uses in the oil industry, and in other industries as well. Theproduced steam can be injected underground for Enhanced Oil Recovery. Itcan also be used to generate hot process water for the mining oilsandsindustry. The high pressure drive steam is generated using acommercially available, non-direct steam boiler, co-gen, Once ThroughSteam Generator (OTSG) or any steam generation system or steam heater.Contaminates, like suspended or dissolved solids within the low qualitywater feed, can be removed in a stable solid (former Liquid Discharge)system. The system can be integrated with a combustion gas fired DirectContact Steam Generator (DCSG) for consuming liquid waste streams orwith distillation water treatment systems.

2. Description of Related Art Including Information Disclosed Under 37CFR 1.97 and 37 CFR 1.98

The injection of steam into heavy oil formations has proven to be aneffective method for EOR and it is the only method currently usedcommercially for recovery of bitumen from deep underground oilsandsformations in Canada. It is known that EOR can be achieved whencombustion gases, mainly CO2, are injected into the formation, possiblywith the use of a DCSG as described in my previous applications. Theproblem is that oil producers are reluctant to implement significantchanges to their facilities, especially if they include changing thecomposition of the injected gas to the underground formation and therisk of corrosion in the carbon steel pipes due to the presence of theCO2. Another option to address these concerns and generate steam fromlow grade produced water with Zero Liquid Discharge (ZLD) is to operatethe DCSG with steam instead of a combustion gas mixture that includes,in addition to steam, other gases like nitrogen, carbon dioxide, carbonmonoxide, etc. The driving steam is generated by a commerciallyavailable non-direct steam generation facility. The driving steam isdirectly used to transfer liquid water into steam and solid waste. InEOR facilities, most of the water required for steam generation isrecovered from the produced bitumen-water emulsion. The produced waterhas to be extensively treated to remove the oil remains that can damagethe boilers. This process is expensive and consumes chemicals. The SteamDrive-Direct Contact Steam Generator (SD-DCSG) can consume thecontaminated water feed for generating steam. The SD-DCSG can be astandalone system or can be integrated with a combustion gas DCSG, asdescribed in this application. The proposed SD-DCSG is also suitable foroilsands mining projects where the Fine Tailings (FT) or Mature FineTailings (MFT) are heated and converted to solids and steam using thedriving steam energy. The produced steam from the SD-DCSG can be used toheat the process water in a direct or non-direct heat exchange. The hotprocess water is mixed with the mined oilsands ore during the extractionprocess.

The method, as described, includes generating additional steam fromhighly contaminated oily water with an option for zero liquid wastedischarge. Superheated steam from an industrial boiler is used as thedriving force for generating additional steam in a direct contact heattransfer with the contaminated water. Fine Tailings from tailing pondscan be also used. A “tailor made” pressure and temperature steam, asrequired for injection into the underground oil bearing formation, isgenerated. This process allows for generation of additional lowertemperature steam from waste water in a high efficiency energy process.The amount of additional steam generated increases with the temperatureof the driving steam, and with the reduction of the pressure of theformation. For low pressure shallow formations, more steam can beproduced in comparison to deep, high pressure formations. Another optionis to recycle a portion of the produced steam through a heater and useit as the driving steam, and thereby minimizing the need for externalsteam as a heat energy source. A portion of the oil component in thewater feed will be converted into hydrocarbon gas, basically serving asa solvent. Additional solvents can be added and injected with the steamto improve the oil recovery. The presented technology has a high thermalefficiency capable of consuming contaminated hot produced water, withoutthe need to reduce the heat to allow effective water treatment. Theprocess can convert the existence of oil contaminates within the feedwater into an advantage by generating solvent. This steam generationdirect contact facility can be located in close proximity to the SAGDpads to use the hot produced water and inject the produced steam intothe injection wells.

The steam for the SD-DCSG can be provided directly from a power station.The most suitable steam will be medium pressure, super-heated steam asis typically fed to the second or third stage of steam turbine. A costefficient, hence effective system will be used to employ a high pressuresteam turbine to generate electricity. The discharge steam from theturbine, at a lower pressure, can be recycled back to the boilerre-heater to generate a superheated steam which is effective as adriving steam. Due to the fact that the first stage turbine, which isthe smallest size turbine, produces most of the power (due to a higherpressure), the cost per Megawatt of the steam turbine will be relativelylow. The efficiency of the system will not be affected as thesuperheated steam will be used to drive the SD-DCSG directly and togenerate injection steam for an enhanced oil recovery unit with ZeroLiquid Discharge (ZLD). A ZLD facility is more environmentally friendlycompared to a system that generates reject water and sludge.

The definition of “Steam Drive-Direct Contact Steam Generation”(SD-DCSG) is that steam is used to generate additional steam from adirect contact heat transfer between the liquid water and the combustiongas. This is accomplished through the direct mixing of the two flows(the water and the steam gases). In the SD-DCSG, the driving steampressure is similar to the combustion pressure and the produced steam isa mixture of the two.

The driving steam is generated in a Non-Direct Steam Generator (like asteam boiler with a steam drum and a mud drum) or in a “Once ThroughSteam Generator” (OTSG) COGEN that uses the heat from a gas turbine togenerate steam, or in any other available design. The heat transfer andcombustion gases are not mixed and the heat transfer is done through awall (typically a metal wall), where the pressure of the generated steamis higher than the pressure of the combustion. This allows for the useof atmospheric combustion pressure. The product is pure steam (or asteam and water mixture, as in the case of the OTSG) without combustiongases.

The excessive energy in the superheated steam is used for generatingadditional lower temperature steam for injection into the formation. Theuse of evaporation water treatment facilities in the oilsands industryallows for the production of superheated steam. The proposed method usesDirect Contact Steam Generation where the superheated steam gas is indirect contact with the liquid produced water. Hydrocarbons, likesolvents, within the produced water will be directly converted to gasand recycled back to the formation, possibly with additional solventsthat can be added to the steam flow. The method generates a “tailormade” pressure and temperature steam, as required for injection into theunderground oil bearing formation while maximizing the amount of thegenerated steam. The simulation in this application shows that for a 263psi system with a constant feed of 25° C. water flow at 1000 kg/hour,there is a need for 12.9 tons/hour of 300° C. steam to gasify 1 ton/hourof liquid water. When higher temperature (500° C.) driving steam isused, there is a need for only 4.1 tons/hour of steam. The examplesimulation results show that the amount of produced steam increases by314% with an increase in the driving steam temperature. The pressureimpact simulation was based on driving steam being at a constanttemperature of 450° C. and with one ton/hour of 25° C. water feed. Thesimulation shows that at pressure of 263 psi, 4.9 tons/hour of drivingsteam is used to gasify the water feed. At a higher pressure of 1450psi, 5.1 tons/hour driving steam will be used. The results show that apressure increase slightly reduces the amount of produced steam. Theimpact of the feed water temperature on the system performance was alsosimulated. It was shown that for a system of constant 12 kw heat sourceat 600 psi, 15.1 kg/hour of feed water was gasified to generateinjection steam. When the produced water temperature was 220° C., 22.4kg/hour was gasified. This shows that the produced water temperature hasa large impact on the overall performance and that by using the hightemperature produced water, the system performance can be increased byclose to 150%. The simulation shows that hydrocarbons, like solventswith the produced water, will be converted to gas and injected with thesteam. The system can also include a heater to recycle a portion of theproduced steam as the driving steam that will be produced locally. Therewas also shown to be an advantage to using hot produced water andminimizing the produced steam pressure drop. This can be achieved bylocating the system close to the injection and production well pad.Make-up steam supplied from a remote steam generation facility can beused to operate a steam ejector with a local steam heater, or be used asthe superheated driving steam. The system is ZLD in nature. It can alsoproduce liquid waste if liquid disposal is preferred.

There are patents and disclosures issued in the field of the presentinvention. U.S. Pat. No. 6,536,523, issued to Kresnyak et al. on Mar.25, 2003, describes the use of blow-down heat as the heat source forwater distillation of de-oiled produced water in a single stage MVCwater distillation unit. The concentrated blow-down from thedistillation unit can be treated in a crystallizer to generate solidwaste.

U.S. patent application Ser. No. 12/702,004, filed by Minnich et al. andpublished on Aug. 12, 2010, describes a heat exchanger that operates onsteam for generating steam in an indirect way from low quality producedwater that contains impurities. In this disclosure, steam is usedindirectly to heat the produced water that includes contaminates. Byusing steam as the heat transfer medium, the direct exposure of the lowquality water heat exchanger to fire and radiation is prevented, thusthere will be no damage due to the redaction of the heat transfer. Theconcentrated brine is collected and delivered for disposal or to a multistage evaporator to recover most of the water and there generates a ZLDsystem. The heat transfer surfaces between the steam and the producedwater will have to be clean or the produced water will have to betreated. The concentrated brine, possibly with organics, will be treatedin a low pressure, low temperature evaporator to increase theconcentration; the higher the concentration is, the lower thetemperature. In my application, due to the direct approach of the heattransfer, the system in ZLD with the highest concentration, possibly upto 100% liquid recovery, while generating solid waste, is at the firststage at a higher temperature due to the direct mixture with thesuperheated dry steam that converts the liquid into gas and solids.

U.S. Pat. No. 7,591,309, issued to Minnich et al. on Sep. 22, 2009,describes the use of steam for operating a pressurized evaporationfacility where the pressurized vapor steam is injected into undergroundformations for EOR. The steam heats the brine water which is boiled togenerate additional steam. To prevent the generation of solids in thepressurized evaporator, the internal surfaces are kept wet by liquidwater and the water is pre-treated to prevent solid build up. Theconcentrated brine is discharged for disposal or for further treatmentin a separate facility to achieve a ZLD system. To achieve ZLD, thebrine evaporates in a series of low pressure evaporators (Multi EffectEvaporator).

U.S. Pat. No. 6,733,636, issued to Heins on May 11, 2004, describes aproduced water treatment process with a vertical MVC evaporator.

U.S. Pat. No. 7,578,354, issued to Minnich et al. on Aug. 25, 2009,describes the use of Multi Effect Distillation (MED) for generatingsteam for injection into an underground formation.

U.S. Pat. No. 7,591,311, issued to Minnich et al. on Sep. 22, 2009,describes a process of evaporating water to produce distilled water andbrine discharge, feeding the distilled water to a boiler, and injectingthe boiler blow-down water from the boiler into the produced steam. Thesolids and possibly volatile organic remains are carried with the steamto the underground oil formation. The concentrated brine is dischargedin liquid form.

U.S. Pat. No. 4,398,603, issued to Rodwell on Aug. 16, 1983, describesproducing steam from a low quality feed water. Superheated steam isintroduced into liquid water in a vessel. The mixture is done in aliquid environment where minerals (solids) are participates and areremoved in a liquid phase from the vessel by withdrawing a waste waterstream. Due to the excess heat within the superheated steam, a portionof the liquid feed water evaporates and produces saturated steam.Because all mixing with the steam is done in a liquid environment, theprocess can only produce saturate (wet) steam with waste liquiddischarge for removing the solids.

This invention's method and system for producing steam for extraction ofheavy bitumen includes the steps as described in the patent figures.

The advantage and objective of the present invention are described inthe patent application and in the attached figures.

These and other objectives and advantages of the present invention willbecome apparent from a reading of the attached specifications andappended claims.

SUMMARY OF THE INVENTION

Steam injection is currently the only method commercially used on alarge scale for recovering oil from deep (non-minable) oil sandsformations. Sometimes additional solvents are used, mainly hydrocarbons.There are a few disadvantages to the existing steam generation methods.For example, the steam is much cleaner than is needed for injection. Toachieve the water quality currently used for steam injection, the wateris extensively treated—the first stage is to separate the oil andde-oiling. To achieve that, the produced water is cooled to atemperature at which it can efficiently be de-oiled to the watertreatment plant feed specifications where it is treated to the boilerfeed water specifications. The need to cool the water decreases theSAGD's overall efficiency. In recent year there has been a shift towardthe use of evaporator water treatment technologies instead of softeningbased technologies. As a result, due to the higher quality of theproduced water, it is possible to increase the produced steamtemperature and pressure. There are other advantages to the use ofevaporators to treat the produced water, such as the ability to usebrackish water with high levels of salts and incorporate a crystallizerto achieve ZLD. The proposed method intends to use the systems andmethods developed for combustion of low quality fuel in gas drivenDirect Contact Steam Generation (DCSG) and to replace the combustion gasdriving fluid with steam, where additional steam is generated by adirect mixture of liquid with superheated steam gas, resulting in arelatively low cost steam achieved by a Steam Drive DCSG.

The method and system of the present invention for steam production (forextraction of heavy bitumen by injecting the steam into an undergroundformation or by using it as part of an above ground oil extractionfacility) includes the following steps: (1) Generating a super heatedsteam stream. The steam is generated by a commercially availablenon-direct steam generation facility, possibly as part of a power plantfacility; (2) Using the generated steam as the hot gas to operate a DCSG(Direct Contact Steam Generator); (3) Mixing the super heated steam gaswith liquid water containing significant levels of solids, oilcontamination and other contaminates; (4) Directly converting liquidphase water into gas phase steam; (5) Removing the solid contaminatesthat were supplied with the water for disposal or further treatment; (6)Using the generated steam for EOR, possibly by injecting the producedsteam into an underground oil formation through SAGD or CSS steaminjection wells.

The presented method and its associated system can be applied to manyexisting oilsands operations. Due to the minimal water treatmentrequirements and the fact that the feed water can be at highertemperatures, it is possible to produce additional steam close to theproduction and the injection wells, on the well pad. The hightemperature of the feed water is an advantage as this heat energy helpsin the production of steam and minimizes the amount of superheateddriving steam consumed. It is possible to operate the SD-DCSG in a ZLDmode where the solids contaminates are extracted in a dry, semi-drystable form. A ZLD facility is more environmentally friendly compared toa system that generates reject water and sludge. However, it is alsopossible to operate the SD-DCSG in liquid waste discharge mode (liquiddischarge mode can be used if disposal caverns or disposal wells areavailable and are approved for disposal usage by the regulators, likethe Energy Resources Conservation Board (ERCB) in Alberta, Canada). Theinvention method can also be operated in a liquid waste discharge mode.This can be done by adjusting the ratio between the produced water andthe driving superheated steam and increasing the water feed flow ordecreasing the superheated driving steam flow. The water feed of thismethod and system for enhanced oil recovery can be water separated fromproduced oil and/or low quality water salvaged from industrial plants,such as refineries, and tailings as make-up water. Both of the abovewill allow oilsands operations to more easily meet environmentalregulations without radical changes to oil recovery and water recyclingtechnologies currently in use.

The excessive energy in superheated steam can be used for generatingadditional lower temperature steam for injection into the formation. Theuse of evaporation water treatment facilities in the oilsands industryallows for the production of superheated steam. The proposed method usesDirect Contact Steam Generation where the superheated steam gas is indirect contact with the liquid produced water. Hydrocarbons, likesolvents, within the produced water will be directly converted to gasand recycled back to the formation, possibly with additional solventsthat can be added to the steam flow. The presented technology generatesa “tailor made” pressure and temperature steam, as required forinjection into the underground oil bearing formation while maximizingthe amount of the generated steam. The simulation shows that for a 263psi system with a constant feed 25° C. water flow at 1000 kg/hour, thereis a need for 12.9 tons/hour of 300° C. steam to gasify 1 ton/hour ofliquid water. When higher temperature (500° C.) driving steam is used,there is a need for only 4.1 tons/hour of steam. The results show thatthe amount of produced steam increases by 314% with a driving steamtemperature increase. The pressure impact simulation was based ondriving steam at a constant temperature of 450° C. and 1 ton/hour 25° C.water feed. The simulation shows that at pressure of 263 psi, 4.9tons/hour of driving steam is used to gasify the water feed. At a higherpressure of 1450 psi, 5.1 tons/hour driving steam will be used. Theresults show that a pressure increase slightly reduces the amount ofproduced steam. The impact of the feed water temperature on the systemperformance was also simulated. It was shown that for a system of aconstant 12 kw heat source at 600 psi, 15.1 kgs/hour of feed water wasgasified to generate injection steam. Where the produced watertemperature was 220° C. temperature, 22.4 kg/hour was gasified. Thisshows that the produced water temperature has a large impact on theoverall performance and that by using the high temperature producedwater, the system performance can be increased by close to 150%. Thesimulation shows that hydrocarbons, like solvents with the producedwater, will be converted to gas and injected with the steam. The systemcan also include a heater to recycle a portion of the produced steam asthe driving steam that will be produced locally. There was shown to bean advantage to using hot produced water and to minimizing the producedsteam pressure drop. This can be achieved by locating the system closeto the injection and production well pad. Make-up steam supplied from aremote steam generation facility can be used to operate a steam ejectorwith a local steam heater, or be used as the superheated driving steam.The system can be ZLD. It can also produce liquid waste if liquiddisposal is preferred.

In another embodiment, the invention can include the following steps:(1) Generating a super heated steam stream. The steam is generated byheating a steam stream in a non-direct heat exchanger; (2) Using thegenerated steam as the hot gas to operate a DCSG (Direct Contact SteamGenerator); (3) Mixing the super heated steam gas with liquid watercontaining significant levels of solids, oil contamination and othercontaminates; (4) Directly converting liquid phase water into the gasphase steam; (5) Removing the solid contaminates that were supplied withthe water for disposal or further treatment; (6) Recycling a portion ofthe generated steam back to the heating process of (1) to be used as thehot gas operating the DCSG. The recycled steam can be cleaned to removecontaminates that can affect the heating process (like silica). Thecleaning process can include any type of filter, precipitators or wetscrubbers. Chemicals (like caustic, magnesium salts or any othercommercially available chemicals) can be added to the wet scrubber toremove contaminates from the steam flow.

In another embodiment, part of the generating steam is condensed andused to wash the produced steam of solid particles in a wet scrubber.Chemicals can be added to the liquid water to remove contaminates. Aportion of the liquid water is recycled back and mixed with thesuperheated steam to transfer it into gas and solids. A portion of thescrubbed saturated steam flow can be recycled and heated to generate asuper heated “dry” steam flow to drive the SD-DCSG and change the liquidflow into steam.

In another embodiment, the scrubbed saturated steam, after the solidsare removed, can be condensed to generate contaminate free liquid water,at a saturated temperature and pressure. The liquid water can be pumpedand fed into a commercially available non-direct steam boiler forgenerating super heated steam to drive the SD-DCSG for transferring theliquid contaminated water into gas and solids.

In another embodiment, the SD-DCSG is integrated with a DCSG that usescombustion gases as the heat source. In that embodiment, the dischargefrom the SD-DCSG can be in a liquid form and it can be used as the watersource for the combustion gas driven DCSG.

The present invention can be used to treat contaminated water using theSD-DCSG in different industries, such as the power industry or chemicalindustry where there is a need to recover the water from a contaminatedwater stream to generate steam with zero liquid discharge.

The system and method's different aspects of the present invention areclear from the following figures.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1, 1A, 1B, 1D, and 1E show the conceptual flowchart of the methodand the system.

FIG. 2 shows a block diagram of an embodiment of the invention.

FIG. 2A shows a schematic of a vertical SD-DCSG.

FIG. 2B shows a block diagram of the embodiment of the invention.

FIG. 2C is schematic view of another embodiment of a reaction chamberapparatus of a high-pressure steam drive direct contact steam generatorof the present invention.

FIG. 2D shows a schematic view of another embodiment of a verticalSD-DCSG.

FIG. 2E shows a schematic view of a SD-DCSG integrated into an open mineoilsands extraction plant.

FIG. 2F shows a schematic view of a SD-DCSG with a non-direct heatexchanger to heat the process water.

FIG. 3 is a schematic view of an illustration of one embodiment of thepresent invention without using an external water source for the drivingsteam.

FIG. 3A is a schematic view of an illustration of another embodiment ofthe present invention.

FIG. 3B is a schematic view of an illustration of a parallel flowSD-DCSG according to FIG. 3A.

FIG. 3C is a schematic view of an illustration of a SD-DCSG with astationary enclosure and an internal rotating element.

FIG. 3D is a schematic view of an illustration of a modification ofFIGS. 3C and 3B for a steam drive Non-Direct contact steam generator.

FIG. 3E shows a schematic view of a parallel flow and a counter flowsteam drive direct contact steam generation system.

FIG. 3F shows a schematic view of a direct contact steam generatingsystem as shown in FIG. 3E with solids separation.

FIG. 3G is a schematic view of a steam drive direct contact steamgenerator apparatus.

FIG. 3H is a schematic view of another configuration of a steam drivedirect contact steam generator apparatus.

FIG. 3I is a schematic view of a steam drive direct contact steamgenerator apparatus.

FIG. 3J is a schematic view of a steam drive direct contact steamgenerator with an internal wet scrubber that generates additional wetsolids free steam.

FIG. 3K is a schematic view of an illustration of another embodiment ofthe present invention.

FIG. 4 is a schematic view of an illustration of still anotherembodiment of the present invention.

FIG. 5 is a schematic diagram of one embodiment of the invention thatgenerates wet scrubbed, clean saturated steam.

FIG. 5A is a schematic view of an illustration of one embodiment of theinvention where a portion of the driving steam water is internallygenerated.

FIG. 5B is a schematic view of the invention with internal distillationwater production for the boiler.

FIG. 5C is a schematic diagram of a method that is similar to FIG. 5Bbut with a different type of SD-DCSG.

FIG. 6 is a schematic diagram of the present invention which includes aSD-DCSG and an EOR facility.

FIG. 6A is a schematic flow diagram of the integration between SD-DCSGand DCSG that uses the combustion gas generated by the pressurizedboiler.

FIG. 6B is a schematic view of a direct contact steam generator withrotating internals, dry solids separation, wet scrubber and saturatedsteam generator.

FIG. 6C is a schematic view of a SD-DCSG and heavy oil extractionthrough steam injection.

FIG. 6D shows a schematic view of a SD-DCSG similar to the system inFIG. 6C.

FIG. 6E is a schematic view of the SD-DCSG with similarities to FIG. 6Dand with externally supplied make-up HP steam.

FIG. 6F shows a schematic view of another embodiment of the presentinvention for generating steam for oil extraction with the use of asteam boiler and steam heater.

FIG. 7 is a schematic view of an integrated facility of the presentinvention with a commercially available steam generation facility andfor EOR for heavy oil production.

FIG. 8 is a schematic view of the invention with an open mine oilsandsextraction facility.

FIG. 9 is another schematic view of the invention with an open mineoilsands extraction facility and a pressurized fluid bed boiler.

FIG. 10 is a schematic diagram of DCSG pressurized boiler and SD-DCSG.

FIG. 11 is a schematic diagram of the present invention which includes asteam generation facility, SD-DCSG, a fired DCSG and MED water treatmentplant.

FIG. 11A is a schematic view of the present invention that includes asteam generation facility, SD-DCSG and MED water treatment plant.

FIG. 11B is a schematic diagram of the present invention that includes asteam drive DCSG with a direct heated Multi Stage Flash (MSF) watertreatment plant and a steam boiler for generating steam for EOR.

FIG. 12 is a schematic view of an illustration of the use of a partialcombustion gasifier with the present invention for the production ofsyngas.

FIG. 13 is a schematic view of the present invention for the generationof hot water for oilsands mining extraction facilities.

FIG. 13A is a schematic view of the process for the generation of hotwater for oilsands mining extraction facilities, with Fine Tailing waterrecycling.

FIG. 13B is a schematic view of the process for the generation of hotwater for oilsands mining extraction facilities, with Fine Tailing waterrecycling.

FIG. 14 is a schematic view of one illustration of the present inventionfor the generation of pre-heated water.

FIG. 15 is a schematic view of the invention with an open mine oilsandsextraction facility.

FIG. 16 is a another schematic view of the invention with another openmine oilsands extraction facility.

FIG. 17 is a schematic view of the invention with still another openmine oilsand extraction facility.

FIG. 18 is a schematic view of the invention with yet another open mineoilsands extraction facility.

FIG. 19 is a schematic view of an illustration of still anotherembodiment of the present invention.

FIG. 20 is a schematic view of an illustration of yet another embodimentof the present invention.

FIG. 21 is a schematic view of an illustration of a boiler, steam driveDCSG, solid removal and Mechanical Vapor Compression distillationfacility for generating distilled water in the boiler for steamgeneration.

FIG. 22 is a graph illustration of a simulation of the process asdescribed in FIG. 2A.

FIG. 23 is another graph illustration of a simulation of the process asdescribed in FIG. 2A.

FIG. 24 is yet another graph illustration of a simulation of the processas described in FIG. 2A.

FIG. 25 is a schematic view of the process of Example 7.

FIG. 26 is a schematic view of the process of Example 8.

FIG. 27 is a schematic view of the process of Example 9.

FIG. 28 is a schematic view of the process of Example 10.

FIG. 29 is a schematic view of the process of Example 11.

FIG. 30 is a graph illustration showing the amount of produced steam asa function of the feed water temperature in the system.

DETAILED DESCRIPTION OF THE DRAWINGS

FIGS. 1, 1A, 1B, 1D, and 1E show the conceptual flowchart of the methodand the system.

FIG. 2 shows a block diagram of an embodiment of the invention. Flow 9is superheated steam. The steam pressure can be from 1 to 150 bar andthe temperature can be between 150° C. and 600° C. The steam flows toenclosure 11, which is a SD-DCSG. Contaminated produced water 7,possibly with organic contaminates, and suspended and dissolved solids,is also injected into enclosure 11 as the water source for generatingsteam. The water 7 evaporates and is transferred into steam. Theremaining solids 12 are removed from the system. The generated steam 8is at the same pressure as that of the drive steam 9 but at a lowertemperature because a portion of its energy was used to drive the liquidwater 7 through a phase change. The generated steam is also at atemperature that is close to the saturated temperature of the steam atthe pressure inside enclosure 11. The produced steam can be furthertreated 13 to remove carry-on solids, reducing its pressure and possiblyremoving additional chemical contaminates. Then the produced steam isinjected into an injection well for EOR.

FIG. 2A shows a schematic of a vertical SD-DCSG. Dry steam 9 is injectedinto vessel 11 at its lower section. At the upper section, water 7 isinjected 3 directly into the up-flow stream of dry steam. The waterevaporates and is converted to steam at a lower temperature but at thesame pressure. Contaminates that were carried on with the water areturned into solids and possibly gas (if the water includes hydrocarbonslike naphtha). The produced gas, mainly steam, is discharged from theSD-DCSG at the top. To prevent carried-on water droplets, demisterpacking 5 can be used at the top of SD-DCSG enclosure 11. The solids 12are removed from the system from the bottom 1 of the vertical enclosurewhere they can be disposed of or treated.

FIG. 2B shows a block diagram of the invention. This figure is similarto FIG. 2 but contains an additional solids removal system as describedin Block 15. Block 15 can include any commercially available Solid-Gasseparation unit. In this particular figure, cyclone separator 19 andelectrostatic separation are represented. High temperature filters, thatcan withstand the steam's temperature, possibly with a back-pressurecleanup system, can be used as well. The steam flow leaving the SD-DCSGcan include solids from the contaminate water 7. A portion of the solids12 can be recovered in a dry or wet form from the bottom of the steamgeneration enclosure 11. The carry-on solids 14 can be recovered fromthe gas flow 8 in a dry form for disposal or for further treatment.

FIG. 2C is another embodiment of a reaction chamber apparatus of ahigh-pressure steam drive direct contact steam generator of the presentinvention. A similar structure can be used with DCSG that usescombustion gas as the heat source to convert the liquid water intosteam. A counter-flow horizontally-sloped pressure drum 10 is partiallyfilled with chains 11 that are free to move inside the drum and areinternally connected to the drum wall. A parallel flow design can beused as well. The chains increase the heat transfer and remove solidsbuild-up. Any other design that includes internal embodiments that arefree to move or that are moving with the rotating enclosure andcontinually lifting solids and liquids to enhance their mixture with theflowing gas can be used as well. The drum 10 is a pressure vessel whichis continually rotating, or rotating at intervals. At a low point of thesloped vessel 10, hot dry steam 8 is generated by a separate unit, likethe pressurized boiler (not shown), and is injected into the enclosure8. The boiler is a commercially available boiler that can burn anyavailable fuel like natural gas, coal, coke, or hydrocarbons such asuntreated heavy low quality crude oil, VR (vacuum residuals), asphaltin,coke, or any other available carbon or hydrocarbon fuel. The pressureinside the rotating drum can vary between 1 bar and 100 bar, accordingto the oil underground formation. The vessel is partially filled withchains 10 that are internally connected to the vessel wall and are freeto move. The chains 10 provide an exposed regenerated surface area thatworks as a heat exchanger and continually cleans the insides of therotating vessel. The injected steam temperature can be any temperaturethat the boiler can supply, typically in the range of 200° C. and 800°C. Low quality water, like mature tailing pond water, rich with solidsand other contaminants (like oil based organics), or contaminated waterfrom the produced water treatment process, are injected into theopposite, higher side of the vessel at section 4 where they are mixedwith the driving dry steam and converted into steam at a lowertemperature. This heat exchange and phase exchange continues at section3 where the heavy liquids and solids move downwards, directly oppositeto the driving steam flow. The driving steam injected at section 2,which is located at the lower side of the sloped vessel, moves upwardswhile converting liquid water to gas. The heat exchange between the drydriving steam and the liquids is increased by the use of chains thatmaintain close contact, both with the hot steam and with the liquids atthe bottom of the rotating vessel. The amount of injected water iscontrolled to produce steam in which the dissolved solids become dry orbecome high solids concentration slurry and most of the liquids becomegases. Additional chemical materials can be added to the reaction,preferably with any injected water. The rotational movement regeneratesthe internal surface area by mobilizing the solids to the dischargedpoint. The rotating movement can agglomerate the solids into smallspheres to increase the solids stability and minimize dust generation.The heat transfer in section 3 is sufficient to provide a homogenousmixture of gas steam and ground-up solids, or high viscosity slurry.Most of the remaining liquid transitions to gas and the remaining solidsare moved to a discharge point 7 at the lower internal section of therotating vessel near the rotating pressurized drum 10 wall. The solidsor slurry are released from the vessel 10 at a high temperature andpressure. They undergo further processing, such as separation anddisposal.

FIG. 2D shows a schematic of a vertical SD-DCSG. It is similar to FIG.2A with the following changes: Vessel 11 includes a liquid water 1 bathat its bottom. The water is maintained at a saturated temperature.Saturated water is recycled and dispersed 3 into the up-flow flow of drysteam 9. The dispersed water evaporates into the up-flowing steam.Contaminates that were carried on with the water are turned into solidsand possibly gas (if the water includes hydrocarbons). The produced gas,mainly steam, is discharged from the SD-DCSG at the top. A portion ofthe saturated water 1 is dispersed at the up-flow stream of dry steam.The water evaporates and is converted to a lower temperature steam.Solids are carried with the up-flow gas 8. Over-sized solids 12 can beremoved from the system from the bottom 1 of the vertical enclosure in aslurry form for further treatment.

FIG. 2E shows a schematic of a SD-DCSG integrated into an open mineoilsands extraction plant for generating the hot extraction water whileconsuming the Fine Tailings generated by the extraction process. Flow 9is superheated steam. The steam flows to enclosure 11 which is aSD-DCSG. Fine Tailings (FT) contaminated produced water 7, is alsoinjected into enclosure 11 as the water source for generating steam. Thewater component 7 evaporates and is transferred into steam. Theremaining solids 12 are removed from the system. The generated steam 8is at the same pressure as that of the drive steam 9 but at a lowertemperature because a portion of its energy was used to drive the liquidwater 7 through a phase change. The generated steam is also at atemperature that is close to (or slightly higher than) the saturatedtemperature of the steam at the pressure inside the enclosure 11. Theproduce steam is fed into a heat exchanger/condenser 13. In FIG. 2E, anon-direct heat exchanger is described. A direct heat exchanger can beused as well. The produced steam condensation energy is used to heat theflow of cold extraction process water 52 to generate a hot process water52A flow at a temperature of 70-90° C. The produced hot process watercan be used in Block A for tarsands extraction. The hot condensate 10that is generated from steam flow 8 can be added to the process water52A or used for other processes as a water source for a High Pressuresteam boiler, as an example. In case that Non-Condensed Gases (NCG) weregenerated 17, they are recovered for further use. (For FT 9 thatcontains low levels of organics, low amounts of NCG will be generated.With the use of direct contact heat exchange between the process water52 and the produced steam 8 at 13 (not shown), the low levels of NCGwill be dissolved and washed by the large amount of process water 14).Block A is a typical open mine extraction oilsands plant as described,for example, in Block 5 in FIG. 8. Flow 7 is fine tailings generatedduring the extraction process. Flow 14 is additional fine tailings fromother sources, like MFT from a tailing pond (not shown). The drivingsteam 9 can be generated by compressing and heating a portion of thegenerated steam, as described in FIG. 3 (not shown).

FIG. 2F shows a SD-DCSG with a non-direct heat exchanger to heat theprocess water and with the combustion of the NCG hydrocarbons as part ofgenerating the driving steam. FTor MFT 7 are injected into a SD-DCDG. InFIG. 2F, a vertical fluid bed SD-DCSG is schematically represented. Anyother SD-DCSG can be used as well, like the horizontal SD-DCDG presentedin FIGS. 3A, 3B, 3C or any other design. The FT 7 are mixed with the drysuper-heated steam flow 9 that is used as the energy source to transferthe liquid water phase in flow 7 to gas (steam) phase by direct contactheat exchange. The FT 7 solids are removed in a stable form 12 wherethey can be economically disposed of and can support traffic. Theproduced steam 8 is condensed in a non-direct heat exchanger/condenser13. The water condensation heat is used to heat the extraction processwater 14. With some tailings types, NCG (Non Condensed Gases) 17 aregenerated due to the presence of hydrocarbons, like solvents used in thefroth treatment or oil remains that were not separated and remained withthe tailings. The NCG 17 is burned, together with other fuel 20 likenatural gas, syngas or any other fuel. The combustion heat is used,through non-direct heat exchange, to produce the superheated drivingsteam 9 used to drive the process. The amount of energy in the NCGhydrocarbons 17 recovered from typical oilsands tailings, even that froma solvent froth treatment process, is not sufficient to generate thesteam 9 to drive the SD-DCSG. It can provide only a small portion of theprocess heat energy used to generate the driving steam 9. One option isto use a standard boiler 18 designed to generate steam from liquid waterfeed 19 from a separate source. Another option is to use a portion ofthe produced steam condensate 23 as the liquid water feed to generatethe driving steam 9. The condensate will be treated to bring it to BFWquality. Treatment units 24 are commercially available. Another optionto generate the driving steam 9 is to recycle a portion of the producedsteam 8. The recycled produced steam 21 is compressed 22. Thecompression is needed to overcome the pressure drop due to the recycleflow and to generate the flow through the heater 18 and the SD-DCSG 11.The compression can be done using a steam ejector with high pressureadditional steam or with the use of any available low pressuredifference mechanical compressor. The recycled produced steam21—possibly after additional cleaning, like wet scrubbing, to removecontaminates like silica—is indirectly heated by combustion heater 18.

FIG. 3 is an illustration of one embodiment of the present inventionwithout using an external water source for the driving steam. SD-DCSG 30includes a hot and dry steam injection 36. The steam is flowing upwardswhere low quality water 34 is injected to the up-flow steam. At least aportion of the injected water is converted into steam at a lowertemperature and is at the same pressure as the dry driving steam 36. Thegenerated steam can be saturated (“wet”) steam at a lower temperaturethan the driving steam. A portion of the generated steam 32 is recycledthrough compressing device 39. The compression is only designed tocreate the steam flow through heat exchanger 38 and create the up flowin the SD-DCSG 30. The compressing unit 39 can be a mechanical rotatingcompressor. Another option is to use high pressure steam 40 and injectit through ejectors to generate the required over pressure and flow inline 36. Any other commercially available unit to create the recycleflow 36 can be used as well. The produced steam, after its pressure isslightly increased to generate the recycle flow 36, and possibly afterthe contaminates are removed in a dry separator or wet scrubber toprotect the heater, flows to heat exchanger 38 where additional heat isadded to the recycled steam flow 32 to generate a heated “dry” steam 36.This steam is used to drive the SD-DCSG as it is injected into its lowersection 30 and the excess heat energy is used to evaporate the injectedwater and generate additional steam 31. The heat exchanger 38 is not aboiler as the feed is in gas phase (steam). There are several commercialoptions and designs to supply the heat 37 to the process. The producedsteam 31 or just the recycled produced steam 32 can be cleaned of solidscarried with the steam gas by an additional commercially availablesystem (not shown). The system can include solids removal; this heatexchanger can be any commercially available design. The heat source canbe fuel combustion where the heat transfer can be radiation, convectionor both. Another possibility can be to use the design of the re-heatheat exchanger typically used in power station boilers to heat themedium/low pressure steam after it is released from the high pressurestages of the steam turbine. This option is schematically shown on FIG.3. Typically, the re-heater 40 supplies the heat to operate the secondstage (low pressure) steam turbine. Accordingly, the feed to there-heater is saturated or close to saturated medium-low steam. As such,this minimizes the re-heater design conversion changes to heat thegenerated steam 31 for generating the superheated steam 36. If anexisting steam power plant is used, the supercritical high-pressuresteam can be used to drive a high pressure steam turbine, while theremaining heat can be used through the re-heater to provide the heat 37to drive the steam generation facility. The advantages of thisconfiguration: a high pressure steam turbine has smaller dimensions andTotal Installed Cost (TIC) compared to medium/low pressure steam turbineper energy unit output.

FIG. 3A is an illustration of one embodiment of the present invention.It is similar to FIG. 3 with the use of a rotating SD-DCSG. The drivingsuperheated (“dry”) steam 36 is injected into a rotating pressurizedenclosure 30. The rotating SD-DCSG enclosure consumes liquid water 34,possibly with solid and organic contaminations, and generates lowertemperature steam 31 and solid waste 35 that can be disposed of in alandfill and can support traffic. The rotating SD-DCSG 30 is describedin FIG. 2C.

FIG. 3B is an illustration of a parallel flow SD-DCSG. It is similar toFIG. 3A with the use of a parallel flow direct contact heat exchangebetween the liquid water and the dry steam. The driving superheated(“dry”) steam 36 is injected into rotating pressurized enclosure 30.Liquid water 34, possibly with solid and organic contaminations, isinjected together with the driving steam at the same side of theenclosure. Lower temperature produced steam 31 and solid waste 35 can bedisposed of in a landfill and can support traffic. The drivingsuperheated steam is generated by recycling a portion of the producedsteam 32. The recycled produced steam is compressed to overcome thepressure loss and generate the required flow. It is indirectly heated 38and recycled back 36 to the SD-DCDG 30.

FIG. 3C is an illustration of a SD-DCSG with a stationary enclosure andan internal rotating element. Super heated driving steam 36 is injectedinto enclosure 30. Low quality liquid water with high levels ofcontaminates, like Fine Tailings generated by an open mine oilsandsextraction plant, is injected into the enclosure. The enclosure ispressurized. The liquid water is evaporated to generate produced steam33. The produced steam 33 is at a lower temperature as compared to thesuperheated driving steam; it is close to the saturated point due to theadditional water that was evaporated and converted to steam. The solidsthat were introduced with the low quality liquid water 34 are removed ina stable form where they can be disposed of in a land fill and cansupport traffic. To increase the direct contact heat transfer within theenclosure 30, moving internals are used. The internals can be anycommercially available design that is used to mobilize slurry and solidsin a cylindrical enclosure. A rotating screw 31 can be used. Therotating movement 32 is provided through a pressure sealed connectionfrom outside the enclosure. The screw mobilizes the solids and drivesthem to the discharge location where they are discharged from thepressurized enclosure.

FIG. 3D is an illustration of a modification of FIGS. 3C and 3B for asteam drive Non-Direct contact steam generator where the heat issupplied by steam to a heated stationary external enclosure and aninternal rotating element to mobilize the evaporating low quality solidsrich water, like MFT. The process includes generating or heating steam36 through indirect heat exchange (not shown). The generated steamenergy 36 is used to indirectly gasify liquid water 34 with solids andorganic contaminates, like fine tailings, so as to transfer said liquidwater from a liquid phase to a gas phase 33. Solids 35 are removed toproduce solids-free gas phase steam 33. The produced steam can befurther condensed to generate heat and water for oil production (notshown). The hot driving steam (there is no need to usie dry superheatedsteam as the driving steam) 36 is heating enclosure 30. Low qualityliquid water with high levels of contaminates, like Fine Tailingsgenerated by an open mine oilsands extraction plant, are injected intothe enclosure. The enclosure is pressurized. The liquid water evaporatesdue to a non-direct heat transfer from the enclosure 30 to generateproduced steam 33. The solids that were introduced with the low qualityliquid water 34 are removed in a stable form 35 where they can bedisposed of in a land fill and can support traffic. To increase thedirect contact heat transfer within the enclosure 30 and to mobilize thesolids and slurry, moving internals are used. The internals can be anycommercially available design that is used to mobilize slurry and solidsin a cylindrical enclosure. The rotating movement can agglomerate thesolids into small spheres to increase the solids stability and minimizedust generation. A rotating screw 31 can be used. The rotating movement32 is provided through a pressure sealed connection from outside theenclosure. The screw mobilizes the solids and drives them to thedischarge location where they are discharged from the pressurizedenclosure. Any other design (like double screws, lifting scoops, orchains) can be used as well. Condensed water 36A from the condensingdriving steam 36 is recycled to the point where it can be re-heated forgenerating additional driving steam 36 or for any other use.

FIG. 3E shows a parallel flow and a counter flow steam drive directcontact steam generation system. In the parallel flow system 1 liquidwater 7, possibly with high levels of suspended and dissolved solidslike fine tailings, produced water, evaporator brine, brackish water,produced gas, carbons, hydrocarbons or any available water feed possiblywith high levels of contaminates, is fed into a longitude enclosure 5.Superheated dry steam 6 is also fed into the same longitude enclosure 4at the same side where the low quality water is injected and where thetwo flows, the liquid and the gas, are mixed in direct contact. Toenhance the mixing and mobilize the generated slurry or solids,mechanical energy is supplied to the enclosure. One possible, simple wayto supply the mechanical energy is by a longitudinal rotating element 9.There are several designs for such a rotating element that can includespirals, scoops, scrapers or any other commercially available design. Itis possible to use a single rotating unit 11 in a circle enclosure 10.It is also possible to use double rotating units 13 and 14 in an ovalenclosure 12 where the multiple rotating units can enhance the mixingand the removal of solids deposits. In the parallel system, the producedsteam 3 is discharged with the solids rich slurry or solids at theenclosure end. To allow efficient heat transfer duration, the enclosurelength is longer than its diameter, typically the length L is at leasttwice the diameter D. The steam-solids mixture is further separated (notshown). In the counter flow system 15 the low quality liquid flow 18,similar to flow 7 in the parallel flow system 1, is fed into a longitudeenclosure with an internal rotating element to introduce mechanicalenergy into the enclosure. The superheated driving steam 16 isintroduced at the opposite end of the enclosure where it is mixed withthe flow of liquids 18. The heat energy in the super heated drivingsteam 16 is directly transferred to the liquid water to generate steam.The slurry or solids are transferred by rotating auger, possibly with aspiral in the opposite direction, to the driving steam 16 flow anddischarged from the longitude system at 17. It is also possible toconnect the parallel flow and the counter flow systems to each otherwhere the discharge from the first system 3 or 17 still containssignificant levels of liquids, possible in a slurry form, which is fedinto the second system 18 or 7.

FIG. 3F shows a direct contact steam generating system as shown in FIG.3E with solids separation. The direct contact parallel flow steamgenerator 1 is similar to FIG. 3E where the solid contaminates areremoved from the steam flow in a separator 10 through a de-pressurizedcollection hopper system that includes valves 12 and 14, de-pressurizedenclosure 13, and solids discharge 15. The enclosure 10 can includeinternals to generate cyclone separation or any other commerciallyavailable solids separation design. A commercially available gas-solidseparation package can be added to the discharged flow 20 to removesolids from the gas stream (not shown). The solids removed from stream20 can be discharged through the de-pressurized hopper system 13.

FIG. 3G is a steam drive direct contact steam generator apparatus. Itincludes a vertical enclosure 2 with steam injection points 6 arrangedaround the enclosure wall. The injection flows 5, 9 are arranged toenhance the mixing flow within the vessel and to protect the enclosurewall from solids build-up. Liquid water 7 injected into the uppersection 1 of the enclosure. The water injection can include a sprayer todisperse the water and enhance the mixture between the liquid water andthe steam. The injected water can be low quality produced water or waterfrom any other source, such as tailings pond water. The injected water 7can include dissolved or suspended solids as well as any other carbon orhydrocarbon contamination. The water is injected at the uppersection—section C. Super heated dry steam 5 is injected at section Blocated below the water injection 7. The dry steam is injectedsubstantially perpendicular to the enclosure wall, possibly with anangle to enhance the mixture of the liquid water and the steam and tominimize the contact between the liquid water and the enclosure wallwhich can prevent build up of solids deposits on the enclosure wall. Thesolids rich contaminates 4 that were introduced into the system with thewater feed 7, after most of the liquid water evaporates into steam, arecollected at the bottom of the enclosure 3 and removed from the system.The injected steam 9 can be dispersed by a nozzle 10 close to theenclosure wall in such a way that part of the steam flow will be spreadand then will generate a flowing movement that will reduce the potentialcontact between the water feed 7 and the enclosure wall. The injectedsteam 5 and the water feed that was converted into steam is released ina gas flow 8 from the upper section of the enclosure 1. The steam flow 8can flow through a demister and a separator that can be locatedinternally in section C or externally to remove water droplets andsolids remains (not shown). The pressure of the produced steam 8 issimilar to the pressure of the superheated driving steam 5, except for asmall difference to generate the up flow movement, and its temperatureis closer to the saturated temperature at the particular enclosurepressure due to the evaporation of the feed water 7.

FIG. 3H is another configuration of a steam drive direct contact steamgenerator apparatus. Sections A and B are described in FIG. 3E.Superheated dry steam 6 is injected into Section B. Any liquid waterthat flows into the up-flow chamber of Section B is converted intosteam. Contaminates, mainly solids, that were carried with the feedwater 3 are removed from the bottom of the enclosure 9 from Section A.The superheated steam 6 flows from Section B into Section C locatedabove B. Section C includes a fluid bed 4. This fluid bed includesliquid, solids and slurry supplied with the feed water 3. Additionalfree moving bodies, like sand, round metal particles, or round ceramicparticles can be added to the fluid bed 4 to enhance the heat transferbetween the up flowing steam and the slurry from the water feed 3. Thefluid bed in Section C can include additional steam injectors (notshown) to mobilize the solids and prevent solids build-ups that canblock the fluid bed. A direct steam injection into Section C can be donein intervals in strong bursts to mobilize the fluid bed and removebuild-ups. A mechanical means to create movement within the fluid bedcan be used as well, possibly in intervals, in case the steam up flowfrom Section B is not sufficient to prevent solidifications within thefluid bed 4 and remove build-ups (not shown). Solids can also be removeddirectly from 4, from the fluid bed section. The produced steam 1 fromwater flow 3 and from the driving super heated steam 6 is used for oilextraction or for other usages. In the case that the low quality waterfeed 3 contains hydrocarbons, a portion of the hydrocarbons will berecovered with the produced steam and injected into the undergroundformation for heavy oil recovery. The produced steam 1 can be furthertreated in a commercially available demister and gas-solids separator toremove water droplets or flying solids carried-on with the generatedsteam flow.

FIG. 3I is a steam drive direct contact steam generator apparatus.Superheated steam 7 is injected into a vertical enclosure at its lowersection. Liquid water 3 is injected into the enclosure above the steaminjection area. The water injection can include a sprayer to dispersethe water and enhance the mixture between the liquid water 3 and thesteam 7. The injected water can be low quality SAGD produced water,boiler blow-down, evaporator brine or water from any other source, suchas open mine tailings pond water. The injected water 3 can includedissolved or suspended solids as well as any other carbon or hydrocarboncontamination. To enhance the mixture of the steam and the water and toremove solids, an internal structure 4 is placed in between the steaminjection section and the water injection section. Internal 4 caninclude a moving bed or any other configuration of free moving elements,like chains 5, that can remove solids build-ups from the supplied water3. Mechanical energy can be introduced into the internal structure 4 togenerate continuous or interval movement between its parts or betweenthe internal structure and the enclosure. Vibration movement can beintroduced to the bottom structure 6 to prevent solids build-ups. Thesolids 9 are collected and removed from a cone 8 in the enclosurebottom. One option is to generate relative movement between the upperbed structure 4 and the lower bed structure 6 and the enclosure wall.Any commercially available design for moving bed internals can be usedas well. The generated steam 2 is released from the upper section of theenclosure 2. The generated steam 1, can be further cleaned in a dry orwet scrubber and used in enhanced oil recovery by injecting itunderground, like in SAGD or CSS, or to heat water in an open mineextraction process.

FIG. 3J is a steam drive direct contact steam generator with an internalwet scrubber that generates additional wet solids free steam.Superheated steam 10 is injected into Section A of the verticalenclosure. Liquid water 5 is injected and dispersed above the dry steaminjection point. A fluid bed, possibly with additional solid particles9, is supported above the steam injection area 10 in Section A. Thefluid bed increases the heat transfer between the up-flowing steam 10and the dispersed water 5. Solids 12 are remove from the bottom ofSection A for disposal or further treatment. The bottom section of thefluid bed can move by mechanical means to generate a moving or vibratingbed. Solids can be recovered from the fluid bed at Section A to maintaina constant solids level. The up-flow generated steam, possibly withsolids particles, flows into section B. In this section, the up flowingsteam is scrubbed by liquid saturated water 7. To generate the contactbetween the liquid saturated water and the steam, a liquid bath 7 can beused where the steam is forced (due to pressure differences) through theliquid water. Another option is to continually recycle hot saturatedliquid water 4 and spray it 2 into the up flowing steam, therebyscrubbing any solids remains and generating additional steam. In FigureJ, both options are presented (the liquid bath is combined with thewater sprayers 2) however it is possible to use only one of thepresented options. If only the liquid bath 7 is used, the feed water 3will be supplied to the liquid bath as a make-up water (not shown) toreplace the water that was evaporated in Section B and water 5, ensuringany solids are scrubbed, from Section B that is supplied to Section Aand evaporated there. The generated solids free saturated steam fromSection B flows into Section C. Section C can include a demister toseparate any droplets carried on with the up-flow steam (not shown). Theproduced solids free steam can be used for oilsands bitumen recoverywith any commercial oilsands plant that requires steam.

FIG. 3K is an illustration of one embodiment of the present invention.An up-flow direct contact steam generator, as described in FIG. 3H or3I, is used to generate steam 9 from superheated steam and liquid water8. Additional designs for direct contact steam generators, like FIGS.2C, 2D and 2E can be used as well. The produced steam 9 flows to anexternal wet scrubber that also generates additional steam. The producedsteam is mixed with liquid water 11, possibly by circulating system 12with sprayers for dispersing the water 3, where any solids remains arescrubbed with the water droplets while wet steam is generated. Liquidwater 8 at a saturated temperature and pressure is continually recycledand injected into the steam generator 2. Water feed, possible with highlevels of contaminates, is fed into the system. Portion 14 of theproduced steam 13 can be used for any industrial use, such as for oilrecovery or for steam use in the chemical industry. The other portion 15of the produced steam is recycled and used to produce dry superheatedsteam 24 to operate the direct contact steam generator 1. The recycledproduced steam 15 can be further filtered in any commercially availablefilter package to remove contaminates like gas silica remains. Water andchemicals 17 can be used in any gas treated commercial package 16. Thesteam 19 is then compressed to recover the pressure drops in therecycled piping and equipment and then flows to steam heater. Dependingon the mechanical compressing system 20 requirements, some heat can beadded to flow 19 prior to the compression. Another option is to use asteam ejector 20 with high pressure steam feed to generate the recycleflow 21. The steam flow 21 is further heated in any commerciallyavailable heating system 23. Heat flow 22 increases the steamtemperature 24 to generate a dry, superheated steam flow that isinjected back into the direct contact steam generator as the drivingsteam.

FIG. 4 is an illustration of one embodiment of the present invention,where the generated steam 44 is saturated and is washed by saturatedwater in a wet scrubber 40 where additional steam is generated. BLOCK 1includes the system described in FIG. 3 where BLOCK 32 can includesolids removal as a means to remove solid particles from the gas (steam)flow. BLOCK 3 generates steam 33 and stable waste 35. The generatedsteam 33 can contain carry-on solid particles and contaminates thatmight create problems with corrosion or solids build ups in the hightemperature heat exchanger. One way to remove the solid contaminates isby the use of a commercially available solid-gas separation unit, asdescribed in FIG. 2B, or with any other prior art solids removal method.However, there is an advantage to wet scrubbing of solids and possiblyother gas contaminates. To improve the removal of the solids and othercontaminates, the steam 33 is directed to a wet scrubber. In oneembodiment, the wet scrubber generates the liquid water for itsoperation. This is done by an internal heat exchanger that recovers heatfrom the steam and generates condensate water. The condensate liquidwater is used for scrubbing the flowing steam in vessel 40. Thecondensate is recycled 41 and used to wash the steam and is then used asa means to improve the heat transfer. Low quality water from theoil-water separation process, fine tailing water from tailings ponds orfrom any other source is pre-heated through heat exchanger 42 whilerecovering heat from the produced steam 34 generated by the SD-DCSG 30.The condensate is recycled in the wet scrubber to wash the steam.Additional chemicals can be added to the condensate to remove gascontaminates. A portion of the condensate with the solids and othercontaminates 43 is removed from vessel 40 to maintain the contaminationconcentration of the condensate so it is constant. Additional lowquality water 47A can be added to the SD-DCSG without pre-heating so asto prevent excessive cooling of the produced steam 33 and to prevent thegeneration of excessive condensate. The generated steam, after goingthrough the wet scrubber, is a clean and saturated (“wet”) steam. Aportion of the clean steam 45 is directed through heat exchanger 38 togenerate “dry” steam to drive the SD-DCSG 30 with sufficient thermalenergy to convert the low quality water feed 34 into steam. The flowthrough the heat exchanger and inside the vessel 30 is generated by anysuitable commercial unit that can be driven by mechanical energy or canbe a jet energy driven compression unit. The produced clean saturatedsteam 46 can be injected into an underground reservoir, like SAGD, foroil recovery, and it can also be used for heating process water for tarseparation or for any other process that consumes steam.

FIG. 5 is a schematic diagram of one embodiment of the invention thatgenerates wet scrubbed, clean saturated steam. BLOCK 1 includes aSD-DCSG 30 as previously described. The generated steam 31 can becleaned of solids in commercial unit 32, previously described. Lowquality water 34, like MFT, produced water or water from any otheravailable source, can be injected into the SD-DCSG 30. Solids 35 carriedby the water 34 are removed. The SD-DCSG 30 is driven by superheated(“dry”) steam that supplies the energy needed for the steam generationprocess. The dry steam 36 is generated by a commercially availableboiler as described in BLOCK 4. Boiler Feed Water (BFW) 49 is suppliedto BLOCK 4 for generating the driving steam. The boiler facility caninclude an industrial boiler, OTSG, COGEN combined with gas turbine,steam turbine discharge re-heater or any other commercially availabledesign that can generate dry steam 36 and that can drive the SD-DCSG 30.In the case where the boiler consumes low quality fuel, like petcoke orcoal, commercially available flue gas treatment will be used. There is alot of prior art knowledge for the facility in BLOCK 4 as it is similarto the facility that is used all over the world for generatingelectricity. The generated steam from the SD-DCSG 37 is supplied toBLOCK 2, which includes a wet scrubber. The wet scrubber 50 can containchemicals like ammonia or any other chemical additive to removecontaminates. The exact chemicals and their concentration will bedetermined based on the particular contaminates of the low quality waterthat is used. The contamination levels are much lower than in directfired DCSG where the water is directly exposed to the combustionproducts, as described in my previous patents. Liquid water 48 isinjected to the wet scrubber vessel 50 to scrub the contaminates fromthe up-flowing steam 37. Liquid water 51, that includes the scrubbedsolids, is removed from vessel 50 and recycled back to the SD-DCSG 30together with the feed water 34. Depending on the particular feed waterquality 34, it can be used in the scrubber. In that case stream 48 and34 will have the same chemical properties and be from the same source.The scrubbed generated steam 45 generated at BLOCK 2 can be used forextracting and producing heavy oil or can be used for any other use.

FIG. 5A is an illustration of one embodiment of the invention where aportion of the driving steam water is internally generated. Theembodiment is described in FIG. 5 with the following changes: BLOCK 3was added and connected to BLOCK 2. This block includes a direct contactcondenser/heat exchanger 40 that is designed to generate hot (saturated)boiler feed water 46 and possibly saturated steam 44. The saturatedsteam 45 from scrubber 50 flows into the lower section of a directcontact heat exchanger/condenser 40 where BFW 42 is injected. From thedirect contact during the heating of the BFW, additional water will becondensed generating additional BFW 46. A portion of the injected andgenerated water 48 is used in wet scrubber 50 to remove contaminationand is then recycled back to the SD-DCSG 30. The additionalcondensate—clean BFW quality water 49—is used in BLOCK 4 for generatingsteam. The condensate is hot—it is at the water or steam saturatedtemperature at the particle system pressure. Addition hot condensate canbe generated and recovered from the system as hot process water for oilrecovery or for other uses. BLOCK 4 can include any commerciallyavailable steam generator boiler capable of producing dry steam 36. InFIG. 5A, a schematic COGEN is described. Gas turbine 62 generateselectricity. The gas turbine flue gas heat is used to generate or heatsteam through non-direct heat exchanger 61. Typically the produced steamis used to operate steam turbines as part of a combined cycle. At leastpart of the produced dry superheated steam 36 is used to operate theSD-DCSG 30.

FIG. 5B is a schematic view of the invention with internal distillationwater production for the boiler. The illustration is similar to theprocess described in FIG. 5A with a different BLOCK 3. The low qualitywater 47 is heated with the saturated, clean (wet scrubbed) steam 45from BLOCK 2 (previously described). The saturated steam 45 condenses onthe heat exchanger 42, located inside vessel 40, while generatingdistilled water 46. A portion of the distilled water 48 is recycled tothe wet scrubber vessel 50 where it removes the solids and generatesadditional wet steam from the partially dry steam generated in theSD-DCSG 30 in BLOCK 1. Additional distilled water 49, possibly afterminor treatment and addition of chemical additives (not shown) to bringit to BFW specifications, is directed to the boiler in BLOCK 4 forgenerating the driving steam. The system can produce saturated steam 44Aor saturated liquid distilled water 44B or both. The produced steam andwater are used for oil production or for any other use.

FIG. 5C is a schematic diagram of a method that is similar to FIG. 5Bbut with a different type of SD-DCSG in Block 1. FIG. 5C includes avertical stationary SD-DCSG. The dry driving steam 36 is fed into vessel30 where the low quality water 34 is fed above it. Due to excessiveheat, the liquid water is converted into steam. The waste discharge atthe bottom 35 can be in a liquid or solid form. BLOCKS 2, 3 and 4 aresimilar to those in the previous FIG. 5B.

FIG. 6 is a schematic diagram of the present invention which includes aSD-DCSG and an EOR facility like SAGD for injecting steam underground.BLOCK 1 is a standard commercially available boiler facility. Fuel 1 andoxidizer 2 are combusted in the boiler 3. The combustion heat isrecovered through a non-direct steam generator for generation ofsuperheated dry steam 9. The combustion gases are released to theatmosphere or for further treatment (like solid particles removal, SOXremoval, CO2 recovery, etc.). The water that is fed to the boiler is fedfrom BLOCK 2, which includes a commercially available boiler treatmentfacility. The required quality of the supplied water is according to theparticular specifications of the steam generation system in use. The drysteam is fed to SD-DCSG 10. Additional low quality water 7 is fed intovessel 11 where the liquid water is transferred to steam due to theexcess heat in the superheated driving steam 9. The generated steam 8,possibly saturated or close to being saturated, is injected into anunderground formation through an injection well 16 for EOR. The producedemulsion 13 of water and bitumen is recovered at the production well 15.The produced emulsion is treated using commercially available technologyand facilities in BLOCK 2, where the bitumen is recovered and the wateris treated for re-use as a BFW. Additional make-up water 14, possiblyfrom water wells or from any other available water source, can be addedand treated in the water treatment plant. The water treatment plantproduces two streams of water—a BFW quality 6 stream as is currentlydone to feed the boilers, and another stream of contaminated water 7that can include the chemicals that were used to produced the highquality BFW, oil contaminates, dissolved solid (like salts) andsuspended solids (like silica and clay). The low quality flow is fed tothe SD-DCSG 10 to generate injection steam.

FIG. 6A is a schematic flow diagram of the integration between SD-DCSGand DCSG that uses the combustion gas generated by the pressurizedboiler. BLOCK 1 includes a DCSG with non-direct heat exchanger boiler asdescribed in my previous applications. Carbon or hydrocarbon fuel 2 ismixed with an oxidizer that can be air, oxygen or oxygen enriched air 1and combusted in a pressurized combustor. Low quality water 12discharged from the SD-DCSG is fed into the combustion unit to recover aportion of the combustion heat and to generate a stream of steam andcombustion gas mixture 4. The solid contaminates 18 are removed in asolid or stable slurry form where they can be disposed of. The steam andcombustion gas mixture 4 is injected into injection well 17 for EOR.Injection well 17 can be a SAGD “old” injection well where the formationoil is partly recovered and large underground volumes are available, aswell as where corrosion problems are not so crucial as, for example, thewell is approaching the end of its service life. Another, preferableoption for using the steam and combustion gas mixture is to inject itinto a formation that is losing pressure and needs to be pressurized bythe injection of addition non-condensable gas, together with the steam.A portion of the combustion energy is used to generate superheated drysteam in a boiler type heat exchanger 5. The generated steam 9 isdriving the SD-DCSG 10. The water for the non-direct boiler 5 issupplied from the commercially available water treatment plant in BLOCK2. Low quality water from BLOCK 2 is fed directly into the SD-DCSG whereit is converted into steam. In this scheme, the conversion is onlypartial as the discharge from 10 is in a liquid form 12. The liquiddischarge 12 is directed to the combustion DCSG to generate an overallZLD (Zero Liquid Discharge) facility. The steam from the SD-DCSG 8 isinjected into an underground formation through an injection well 16 forEOR.

FIG. 6B described a direct contact steam generator with rotatinginternals, dry solids separation, wet scrubber and saturated steamgenerator. Super heated driving steam 13 is fed into a direct contactsteam generator where it is mixed with water, possibly withcontaminates. The excessive heat energy in the steam evaporates thewater to generate additional steam. Solids 6 are removed from the systemin a dry or slurry form. The produced steam is treated in a commerciallyavailable gas treatment unit in Block B. An inlet demister, to removecarried-on liquid droplets, can be incorporated in Block B. Anycommercially available unit to remove solids and contaminates can beused, such as cyclone solids removal system schematically described inB1, a high temperature filter B2, an electrostatic precipitator B3 or acombination of these with any other commercially available design. Thesolids are removed in a dry form are added to the solids removed fromthe steam generator 14. The solids lean flow 5 is fed into a saturatedsteam generator and a wet scrubber 2. Liquid water is recycled anddispersed into the flowing steam. A portion of the liquid waterevaporates. The water droplets remove contaminates. Chemicals likeanti-foaming, flocculants, Ph control and other commercially availablechemicals to control the process efficiency and prevent corrosion can beadded to the recycled water 11. Make-up water 10 can be added to thesystem to replace the water converted into steam and to replace therecycled water with contaminates, back to the feed water 13. Thescrubbed solids free generated steam 8 is supplied from the system forother usages.

FIG. 6C includes SD-DCSG and heavy oil extraction through steaminjection. Emulsion of steam, water bitumen and gas is produced from aproduction well 10, like a SAGD well. The produced flow 1 is separatedin a separator 3 (located in BLOCK A) to generate water rich flow 5 withcontaminates like sand, and hydrocarbons rich flow 4. There are a fewcommercial designs for separators that are currently used by theindustry. Chemicals can be added to the separation process. Thehydrocarbon rich flow 4 is further treated in processing plant at BLOCKB. Flow 4 is further separated into the produced bitumen, usuallydiluted with light hydrocarbons to enhance the separation process and toreduce the viscosity which allows the flow of the bitumen in thetransportation lines. In BLOCK B, the produced water that remained withthe flow 4 is de-oiled and used, usually with make-up water from waterwells, for generating super-heated steam 6. The water rich flow 5, at ahigh temperature that is close to the produced emulsion temperature, ispumped into a SD-DCSG 7 where it is mixed with the dry superheated steam6 to generate additional steam for injection 2. Light hydrocarbons inflow 5 evaporate due to the heat required to generate hydrocarbons thatare injected with the injection steam 2 into the underground formation11. Additional solvents can be added to the injection steam 2—it is acommon practice to add solvents to the generated steam for injection. Itis known that hydrocarbons that are mixed with the steam can improve theoil recovery. The SD-DCSG 7 includes rotating internals to enhance themixture between the two phases and to mobilize the generated slurry andsolids. The solids 8 are removed from the system for landfill disposal13 or for any other use. The heat energy within flow 5 from separator 3increases the quantity of steam generated in SD-DCSG 7 and by thatimproves the overall thermal efficiency of the system. The generatedsteam 2 is injected, possibly after additional contaminate removaltreatment and pressure control (not shown), into an injection well 11for EOR. The SD-DCSG 7 is a parallel flow steam generator, as describedby Unit 1 in FIG. 3E, however, any other SD-DCSG design like the counterflow SD-DCSG as described by Unit 15 in FIG. 3E, or the rotating orfluid bed units as described in drawings 2C, 2D and 3C-3J can be used aswell.

FIG. 6D includes a SD-DCSG similar to the system in 6C, where thesuperheated driving steam is generated by recycling and re-heating theproduced steam generated by the SD-DCSG 7. A mixture of steam, water,bitumen and gas is produced from a production well 10, like a SAGD well.The produced flow 1 is separated in a separator 3 located in BLOCK A togenerate water rich flow 5 and hydrocarbons rich flow 4. There are a fewcommercial designs for separators that are currently used by theindustry. Chemicals can be added to the separation process. Thehydrocarbon rich flow is further treated in a processing plant at BLOCKB. The water rich flow 5, possibly with hydrocarbons and othercontaminates like sand, is at a high temperature that is close to theproduced emulsion temperature. The heat energy within flow 5 increasesthe quantity of steam generated in SD-DCSG 7 for a given amount ofsuperheated driving steam 6. Flow 5 is pumped into a SD-DCSG 7 where itis mixed with dry superheated steam 6 to generate additional steam 18.Any available design for mixing the water and the steam to generateadditional steam and solids or slurry discharge can be used as well. Thesolids or slurry 8 are removed from the system for landfill disposal 13or for any other use. The produced steam 18 is split into two flows—flow2 of the generated steam 18 is injected, possibly after additionalcontaminate removal treatment and pressure control (not shown), into aninjection well 11 for EOR. The other part of flow 18, flow 12, isrecycled back to BLOCK C. Depending on the recycled steam quality andthe feed requirements of the compressing and heating units, it can bepre-cleaned by any commercially available cleaning technologies. Therecycled produced steam is compressed by a mechanical compressor, steamejector or any other available unit 14 and then indirectly heated byheat flow 15 to generate a super heated driving steam flow 6. Theheating can be done with any available heating unit that can heat steam,possibly with hydrocarbons remains. Electrical heaters for small units,carbon (like coal, petcoke etc.) combustion units for large scale, orhydrocarbon fired (like natural or produced gas, bitumen etc.) formedium and large size units can be used as facility 16 for heating theproduced steam, possibly with small amounts of hydrocarbon gas togenerate the dry, superheated driving steam 6. The superheated drivingsteam 6 is injected to the SD-DCSG 7 where it is mixed with the producedwater 5.

FIG. 6E is a schematic view of the SD-DCSG with similarities to FIG. 6Dand with externally supplied make-up HP steam. A mixture of steam,water, bitumen and gas is produced from a production well 10, like aSAGD well. The produced flow 1 is separated in a separator 3 located inBLOCK A to generate water rich flow 5 and hydrocarbons rich flow 4.There are a few commercial designs for separators that can be used.Chemicals can be added to the separation process. The hydrocarbon richflow is further treated in a commercially available oil and waterprocessing plant at BLOCK B. There are commercially availabletechnologies and designs for such plants—some are used by the oilsandsthermal insitue industry (like SAGD processing plant). The water richflow 5, possibly with hydrocarbons and other contaminates like sand, isat a high temperature close to the produced emulsion 1 temperature. Flow5 is pumped into a SD-DCSG 7 where it is mixed with dry superheatedsteam 6 to generate additional steam 18. The SD-DCSG is a counter flowdesign as described by Unit 15 in FIG. 3E. Any available design formixing the water and the steam to generate additional steam and solidsrich water can be used as well. The solids or slurry is removed from thesystem through separator 20 and de-compression system 21 in a stableform 22. The produced steam 18 is split into two flows—flow 2 of thegenerated steam 18 is injected, possibly after additional contaminateremoval treatment and pressure control (not shown), into an injectionwell 11 for EOR or for any other usage in the mining industry or in anyother industry that required large quantities of steam. Additionalsolvents can be added to the injection steam 2—it is a common practiceto add solvents to the generated steam for injection. The other partfrom flow 18, flow 12, is recycled to be re-heated and used as thesuperheated driving steam. In non-direct contact heater 16, additionalheat Q is added to the steam flow 12 to generate superheated dry steam13. The heating can be done with any available heating facility. Thissuperheated steam is compressed with the pressure energy from HighPressure (HP) make-up steam 6 generated in BLOCK B. The make-up steam isproduced from the produced water that remains in flow 4. The producedwater is treated in the process facility in BLOCK B that includesde-oiling and possibly de-mineralization before being used in acommercially available high pressure boiler or OTSG for generating highpressure steam 6. Additional make-up water 24 is usually required tocompensate for the water loss in the formation and for the waste waterrejected from the water treatment facility in BLOCK B. The make-up wateris usually supplied from a water well 25 or can be from any availablewater source. Disposal water 23 from the water processing facility inBLOCK B, possibly with oil and solids, can be recycled to the SD-DCSG 7together with stream 5 as the water feed to 7.

FIG. 6F describes another embodiment of the present invention forgenerating steam for oil extraction with the use of a steam boiler andsteam heater. A mixture 36 of steam, water, bitumen and gas is producedfrom a production well 32, like a SAGD production well. The producedflow 36 is separated in a separator 33 to separate the produced gas 38from the produced liquids 37. The produced gas 38 can include reservoirgas, mainly light hydrocarbons and possibly lifting gas, in case liftinggas is used to lift the produced liquids to the surface (not shown). Theproduced gas is used in the process as lifting gas. It can also used asfuel for the boilers. The produced liquid emulsion 37 is cooled in heatexchanger 34 while heating the boiler feed water 40 to generatepre-heated boiler feed water. The cooled liquid mixture 39, after theproduced gas was already removed, is fed into separator 35. Chemicals,sometimes with solvents like light hydrocarbons, can be added to theproduced liquid 39 to support the separation process, break theemulsion, and prevent foaming. The separation vessel 35 separates thewater liquid 43 from the bitumen 41. The separation process is a wellknown process within the heavy oil industry. The gas separator reactor33 and the water-oil separator reactor 35 are commercially availableunits. Any additional configuration to enhance the gas-water-oilseparation can be used as well. The produced oil 41 is further treatedin a commercially available process area BLOCK 1 commonly used with theinsitue thermal oil recovery industry, like SAGD or CSS. Solvents can beadded to the produced bitumen 41 to remove the water remains and othercontaminates. BLOCK A includes a commercially available water treatmentfacility, like evaporators, to generate boiler feed quality water 40.The water feed to the water treatment plant in BLOCK 1 can be from thewater remains in flow 41. Additional water can be directed to the watertreatment plant from water 43 that was separated in vessel 35. Theproduced water used as feed to the boiler feed water treatment plant isde-oiled to remove oil traces that can impact the water treatmentprocess in BLOCK 1. Additional make-up water can be added to the processin BLOCK 1 from any other water source, such as water wells. Usually themake-up water does not include organic contaminates so it is easier totreat them with evaporators and other commercially availabledistillation units. (See Society of Petroleum Engineers paper No137633-MS Titled “Integrated Steam Generation Process and System forEnhanced Oil Recovery” presented by M. Betzer at the CanadianUnconventional Resources and International Petroleum Conference, 19-21Oct. 2010, Calgary, Alberta, Canada.) The produced water flow 7,possibly with solids contaminates and oil remains, is mixed withsuperheated steam 6. Due to the contaminates within the produced waterfeed 7, a rotating internal 2 is used to enhance the mixture and removebuild-ups within enclosure 1. Due to the driving steam's 6 hightemperatures (compared to the saturated steam temperature at the systempressure), liquid water from Flow 7 is converted to steam. The amount ofwater converted is a function of the ratio of the driving steam 6 andthe liquid water 7. If disposal wells are available, it is possible toconvert only a portion of the water into steam and dispose of theremaining water with the contaminated solids 12 in a disposal well 13.Heat can be recovered from the disposal liquid flow 12 through a heatexchanger (not shown). The produced steam 20 is separated from thedisposal flow 12 or 15 in a separation enclosure 10. If disposal wellsfor disposing fluids are not available, or a ZLD facility is preferred,most of the water 7 can be converted into steam, generating solids or astable slurry 15 for landfill disposal 16 or for further treatment. Theproduced steam flow 20 is used for injection for thermal oil recoverythrough an injection well. A portion 21 of the produced steam 20 is usedto generate the driving superheated steams 6. The clean BFW 28 is usedfor generating steam through a commercial boiler or OTSG that includes aheat exchanger 26 to generate High Pressure steam 24. Any type ofcommercially available boiler and steam separation vessel can be used.The produced HP steam 24 pressure energy is used to recycle steam 21 toheater 27 to generate superheated dry steam stream 6 to drive the steamgeneration process at 1. The pumping and circulation of the producedsteam 21 is done through steam ejector 23 that uses the pressure of theHP steam as the energy source to compress and circulate portion 21 ofthe produced steam 20 through the heat exchanger 27. As described in theother examples, the produced steam 21 can be further treated in aseparate unit to remove contaminates, like silica, from the producedsteam flow that can affect the super heater heat exchanger's 27performance and create deposits. There are a few technologies that canbe used. One option is to use a liquid scrubber with saturated liquidwater, possibly with chemicals, like magnesium oxide, caustic soda orother chemical additives, to remove contaminates that can affect theperformance of the non-direct heat exchanger 27, or in some cases thesteam lines and the injection well 31. Other technological solutionsavailable to remove the undesired contaminates from the steam gas flowcan be used as well. The feed water 40 is a treated water with lowlevels of contaminates, as required by ASME specifications for boilerfeed water. There is a lot of knowledge and commercially availablepackages to generate the BFW 40 used for generating the high pressuresteam 24. In the current sketch, the boiler integrates the steamgeneration section 26 and the re-heater section 27 for generatingsuper-heated driving steam 6 from the produced steam 21 and the highpressure driving steam 24 for operating the ejector and using thesuper-heated steam as a driving steam. It is possible to separate theproduction of the high pressure steam 24 from the superheated steam intotwo separate units while the steam 24 is generated through a packageboiler, OTSG or any other type of commercially available boiler, withany type of carbon or hydrocarbon fuel. The produced steam 21 is heatedto generate superheated driving steam with any commercially availableheat exchanger design. The heater can be integrated into the boiler or aseparate unit with any available heater design. The steam generationunit can be located on the well pads or in close proximity to the wellpads. This arrangement will minimize the heat losses and allow the useof the produced water heat. The high pressure steam 24 required tooperate the ejector can also be produced remotely in BLOCK 1, whereas onthe pad there will only be steam heater 27.

FIG. 7 is a schematic view of an integrated facility of the presentinvention with a commercially available steam generation facility andfor EOR for heavy oil production. The steam for EOR is generated using alime softener based water treatment plant and an OTSG steam generationfacility. This type of configuration is the most common in EORfacilities in Alberta. It recovers bitumen from deep oil sand formationsusing SAGD, or CSS, etc. Produced emulsion 3 from the production well54, is separated inside the separator facility into bitumen 4 and water5. There are many methods for separating the bitumen from the water. Themost common one uses gravity. Light hydrocarbons can be added to theproduct to improve the separation process. The water, with some oilremnants, flows to a produced water de-oiling facility 6. In thisfacility, de-oiling polymers are added. Waste water, with oil andsolids, is rejected from the de-oiling facility 6. In a traditionalsystem, the waste water would be recycled or disposed of in deepinjection wells. The de-oiled water 10 is injected into a warm or hotlime softener 12, where lime, magnesium oxide, and other softeningchemicals are added 8. The softener generates sludge 13. In a standardfacility, the sludge is disposed of in a landfill. The sludge issemi-wet, and hard to stabilize. The softened water 14 flows to a filter15 where filter waste is generated 16. The waste is sent to anion-exchange package 19, where regeneration chemicals 18 are continuallyused and rejected with carry-on water as waste 20. In a standard system,the treated water 21 flows to an OTSG where approximately 80% qualitysteam is generated 27. The OTSG typically uses natural gas 25 and air 26to generate steam. The flue gas is released to the atmosphere through astack 24. Its saturated steam pressure is around 100 bar and thetemperature is slightly greater than 300 C. In a standard SAGD system,the steam is separated in a separator to generate 100% steam 29 (forEOR) and blow-down water. The blow down water can be used as a heatsource and can also be used to generate low pressure steam. The steam,29 is delivered to the pads, where it is processed and injected into theground through an injection well 53. In the current method, additionaldry superheated steam flow is produced to drive the SD-DCSG in BLOCK 1to generate additional injection steam from the waste water stream. Theproduction well 54, located in the EOR field facilities BLOCK 4,produces an emulsion of water and bitumen 3. In some EOR facilities,injection and production occur in the same well, where the steam can be80% quality steam 27. The steam is then injected into the well with thewater. This is typical of the CSS pads where wells 53 and 54 arebasically the same well. The reject streams include the blow down waterfrom OTSG 23, as well as the oily waste water, solids, and polymerremnants from the produced water de-oiling unit. This also includessludge 13 from the lime softener, filtrate waste 16 from the filters andregeneration waste from the Ion-Exchange system 20. The reject streamsare collected 33 and injected directly 33A into Steam SD-DCSG 30 inBLOCK 1. The SD-DCSG can be vertical, stationary, horizontal orrotating. Dry solids 35 are discharged from the SD-DCSG, after most ofthe liquid water is converted to steam. The SD-DCSG generated steam 31temperatures can vary between 120 C and 300 C. The pressure can varybetween 1 bar and 50 bar. The produced steam 32 can be injected directly45A into the injection well 53, possibly after additional solids andcontamination removal in BLOCK 32. Another option is to wash thegenerated steam in wet scrubber 50 in BLOCK 2. BLOCK 2 is optional andcan be bypassed by flows 33A and 45A. The produced steam from theSD-DCSG 31 is injected into a scrubber vessel 50 where the steam gas iswashed with saturated water 48 that was condensed from the produced gas31 or from additional liquid water supplied to the wet scrubber vessel50 in order to remove the solid remnants and possibly chemicalcontaminates. Solid rich water 51 is continually removed from the bottomof vessel 50. It is recycled back to the SD-DCSG, where the solids areremoved in dry or semi-dry form 35. The liquid water is converted backto steam 31. The saturated wash water in vessel 50 is generated byremoving heat through non-direct heat exchange with the feed water 33. Aportion of the steam condenses to generate washing liquid water atvessel 50. The liquid water is continually recycled to enhance thewashing and the wet scrubbing. The SD-DCSG is driven by superheatedsteam generated by the steam generator 23 or generated in a separateboiler or in a separate heat exchanger within the boiler (re-heater typeheat is exchanged to heat steam to produce a superheated steam). Thereare many varieties of commercially available options to generate the drysteam needed to drive the process in the SD-DCSG. The generated cleansteam 45 is injected into an underground formation for EOR.

FIG. 8 is a schematic of the invention with an open mine oilsandsextraction facility, where the hot process water for the ore preparationis generated from condensing the steam produced from the fine tailingsusing a SD-DCSG. A typical mine and extraction facility is brieflydescribed in BLOCK 5. The tailing water 27 from the oilsand minefacility is disposed of in a tailing pond. The tailing ponds are builtin such a way that the sand tailings are used to build the containmentareas for the fine tailings. The tailing sources come from ExtractionProcess. They include the cyclone underflow tailings 13, mainly coarsetailings, and the fine tailings from the thickener 18, where flocculantsare added to enhance the solid settling and recycling of warm water.Another source of fine tailings is the Froth Treatment Tailings, wherethe tailings are discarded using the solvent recovery processcharacterized by high fines content, relatively high asphaltene content,and residual solvent. (See “Past, Present and Future Tailings, TailingExperience at Albian Sands Energy” a presentation by J. Matthews fromShell Canada Energy on Dec. 8, 2008 at the International Oil SandsTailings Conference in Edmonton, Alberta). A sand dyke 55 contains atailing pond. The sand separates from the tailings and generates a sandbeach 56. Fine tailings 57 are put above the sand beach at themiddle-low section of the tailing pond. Some fine tailings are trappedin the sand beach 56. On top of the fine tailings is the recycled waterlayer 58. The tailing concentration increases with depth. Close to thebottom of the tailing layer are the MFT. (See “The Chemistry of OilSands Tailings: Production to Treatment” presentation by R. J. Mikula,V. A. Munoz, O. E. Omotoso, and K. L. Kasperski of CanmetENERGY, Devon,Alberta, Natural Resources Canada on Dec. 8, 2008 at the InternationalOil Sands Tailings Conference in Edmonton, Alberta). The recycled water41 is pumped from a location close to the surface of the tailing pond(typically from a floating barge). The fine tailings that are used forgenerating steam and solid waste in this invention are the MFT. They arepumped from the deep areas of the fine tailings 43. MFT 43 is pumpedfrom the lower section of the tailing pond and is then directed to theSD-DCSG in BLOCK 1 and in BLOCK 3. The SD-DCSG that includes BLOCKS 1-4is described in FIG. 5B. However, any available SD-DCSG that cangenerate gas and solids from the MFT can be used as well. Due to theheat from the superheated steam and pressure inside the SD-DCSG, the MFTturns into gas and solids as the water is converted to steam. The solidsare recovered in a dry form or in a semi-dry, semi-solid slurry form.The semi-dry slurry form is stable enough to be sent back into theoilsands mine without the need for further drying to support traffic.The produced steam needed for extraction and froth treatment, isgenerated by a standard steam generation facility 61 used to generatethe driving steam for the DCSG in BLOCK 1, or from the steam producedfrom the SD-DCSG 62. The generated saturated steam 47 is mixed with theprocess water 41 in mixing enclosure 45 to generate the hot water 52used in the extraction process in BLOCK 5. By continually consuming thefine tailing water 43, the oil sand mine facility can use a much smallertailing pond as a means of separating the recycled water from the finetailings. This solution will allow for the creation of a sustainable,fully recyclable water solution for open mine oilsands facilities.

FIG. 9 is a schematic view of the invention with an open mine oilsandsextraction facility and a prior art commercially available pressurizedfluid bed boiler that uses combustion coal for a power supply. Examplesof pressurized boilers are the Pressurized Internally CirculatingFluidized-bed Boiler (PICFB) developed and tested by Ebara, and thePressurized-Fluid-Bed-Combustion-Boiler (PFBC) developed byBabcock-Hitachi. Any other pressurized combustion boiler that cancombust petcoke or coal can be used as well. BLOCK 1 is a prior artPressurized Boiler. Air 64 is compressed 57 and supplied to the bottomof the fluid bed combustor to support the combustion. Fuel 60, likepetcoke, is crushed and grinded, possibly with lime stone 61 and water62, to generate pumpable slurry 59. The water 62 is recycled water witha high level of contaminates 38, as discharged from the SD-DCSG 28. Someportion of stream 38A can be injected above the combustion area todirectly recover heat from the combustion gas to generate steam. Theboiler includes an internal heat exchanger 63 to generate high pressuresteam 51 to drive the SD-DCSG. The steam 51 is generated from steamboiler drum 52 with boiler water circulation pump 58. The boiler heatexchanger 63 recovers energy from the combustion. BFW 37 is fed to theboiler to generate steam 51. The steam can be heated again in a boilerheat exchanger (not shown) to generate a superheated steam stream. Thesteam is used to drive the SD-DCSG 28. The boiler generates pressurizedcombustion gas and steam mixture 1 from the SD-DCSG discharged water 24at an average pressure of 103 kpa and up to 1.5 Mpa, and temperatures of200 C-900 C. The discharge flow is treated in BLOCK 3 to generate asteam and combustion gas mixture for EOR. The mixture 8 is injected intoan underground formation through an injection well 7. There is no needto remove solids from the combustion gas 1 because this gas is fed tothe DCSG in BLOCK 3 that works as a wet scrubber and removes solids andpossibly contaminated gases like SOx and NOx while creating a steam andcombustion gas mixture. Solids from the fluid bed of the PFBC 55 can berecovered to maintain the fluid bed solids level (this is a commonpractice in FBC (Fluid Bed Combustion) and PFBC). The fluid bed solidscan be mixed with the DCSG solids from BLOCK 3 (not shown). Thepressurized combustion gases leaving AREA#1 are mixed with theconcentrate effluent from SD-DCSG 28 and possibly with other low qualitywaste water and slurry sources, like HLS/WLS sludge produced by SAGD/CSSwater treatment plant (not shown). BLOCK 2 includes a commerciallyavailable EOR facility, like SAGD, where the water and bitumen emulsionis treated to generate BFW quality water and low quality water that isfed into the SD-DCSG. There will be two types of injection wells—for theinjection of pure steam from the SD-DCSG 6 and for the injection of amixture of steam and combustion gases, mainly CO2 7. It is possible tocombine the two types of EOR fluids in one production facility where theaging injection wells will be converted from pure steam to a steam andcombustion gas mixture to pressurize the underground formation andincrease the bitumen recovery due to the dissolved CO2 which increasesthe bitumen fluidity.

FIG. 10 is a schematic diagram of DCSG pressurized boiler and SD-DCSG.Fuel 2 is mixed with air 55 and injected into a PressurizedFluidized-Bed Boiler 51. The fuel 2 can be generated from thewater-bitumen separation process and includes reject bitumen slurry,possibly with chemicals that were used during the separation process,and sand and clay remains. Additional low quality carbon fuel can beadded to the slurry. This carbon or hydrocarbon fuel can include coal,petcoke, asphaltin or any other available fuel. Lime stone can be addedto the fuel 2 or to the water 52 to remove acid gases like SOx. TheFluidized-Bed boiler is modified with water injection 52 to convert itinto a DCSG. It includes reduced capacity internal heat exchangers torecover less combustion heat. The reduction in the heat exchanger'srequired capacity is because more combustion energy will be consumed dueto the direct heat exchange with the water within the fuel slurry 2 andthe additional injected solids rich water 52 thereby leaving lessavailable heat to generate high pressure steam through the boiler heatexchangers 56. The boiler produces high-pressure steam 59 fromdistilled, de-mineralized feed water 37. The produced steam 59, or partof it 31, can be re-heated in re-heater 56 to generate super heatedsteam 32 to operate the SD-DCSG in BLOCK 3. There are severalpressurized boiler designs for BLOCK 1 that can be modified with directwater injections. One example of such a design is the EBARA Corp. PICFB(see paper No. FBC99-0031 Status of Pressurized Internally CirculatingFluidized-Bed Gasifier (PICFG) development Project dated 16-19 May, 1999and U.S. RE37,300 E issued to Nagato et al on Jul. 31, 2001). Any othercommercially available Pressurized Fluidized Bed Combustion (PFBC) canbe used as well. Another modification to the fluid bed boiler can bereducing the boiler combustion pressure down to 102 kpa. This willreduce the plant TIC (Total Installed Cost) and the pumps andcompressors' energy consumption. The superheated steam 32 is supplied toBLOCK 3 where it is used by the SD-DCSG 28 for generating additionalsteam from low quality water. BLOCK 2 includes a water treatmentfacility as previously described. The steam and combustion gas mixturestream 1 is supplied to BLOCK 2 where the water and heat can be used forgenerating clean BFW in the evaporation/distillation facility. Thepressure energy in flow 1 can be used to separate CO2 from the NCG usingcommercially available membrane technologies. The combustion oxidizer,like air 55, is injected at the bottom of the boiler to maintain thefluidized bed. High pressure 100% quality steam 59 is generated fromdistilled water 37 through heat exchange inside the boiler 51. Thegenerated steam 59 can be further heated in heat exchanger 56 togenerate super-heated steam 32 that is used in BLOCK 3 as the drivingsteam for the SD-DCSG 28. The steam generated in BLOCK 3 is injected,through an injection well 16, into an underground formation for EOR.Hydrocarbons and water 13 are produced from the production well 15. Themixture is separated in a commercially available separation facility inBLOCK 2.

FIG. 11 is a schematic diagram of the present invention which includes asteam generation facility, SD-DCSG, a fired DCSG and MED water treatmentplant. BLOCK 1 is a standard, commercially available steam generationfacility that includes an atmospheric steam boiler or OTSG 7. Fuel 1 andair 2 are combusted under atmospheric pressure conditions. Thedischarged heat is used to generate steam 5 from de-mineralizeddistilled water 29. The combustion gas is discharged through stack 3.The generated steam is supplied to SD-DCSG 11 in BLOCK 4 which generatesadditional steam from the concentrated brine 38 discharged from the MEDin BLOCK 2. The generated steam 8 is injected into an undergroundformation 6. The liquid discharge 14 from SD-DCSG 11 is injected into aninternally fired DCSG 15 in BLOCK 3. Carbon fuel 41, like petcoke orcoal slurry, is mixed with oxygen-rich gas 42 and combusted in a DCSG15. Discharged liquids from the SD-DCSG 11 are mixed with thepressurized combustion gas to generate a stream of steam-rich gas andsolids 13. To reduce the amount of SO2, limestone can be added to thebrine water 14 or to the fuel 41 injected into the DCSG, in order toreact with the SO2. The solids are separated in separator 16. Theseparated solids 17 are discharged in a dry form from the solidsseparator 16 for disposal. The steam and combustion gas 12 flows to heatexchanger 25 and condenser 28. The steam in gas flow 12 is condensed togenerate condensate 24. The condensate is treated (not shown) to removecontaminants and to generate BFW that is added to the distillate BFW 29and then supplied to the steam generation facility. The NCG(Non-Condensation Gas) 40 is released to the atmosphere or used forfurther recovery, like CO2 extraction. The heat recovered in heatexchanger 28 is used to generate steam to operate the MED 30 (acommercially available package). The water 1 fed to the MED is de-oiledproduced water, possibly with make-up underground brackish water. TheMED takes place in a series of vessels (effects) 31 and uses theprinciples of condensation and evaporation at a reduced pressure. Theheat is supplied to the first effect 31 in the form of steam 26. Thesteam 26 is injected into the first effect 31 at a pressure ranging from0.2 bar to 12 bar. The steam condenses while feed water 32 is heated.The condensation 34 is collected and used for boiler feed water 37. Eacheffect consists of a vessel 31, a heat exchanger, and flow connections35. There are several commercial designs available for the heatexchanger area: horizontal tubes with a falling brine film, verticaltubes with a rising liquid, a falling film, or plates with a fallingfilm. The feed water 32 is distributed on the surfaces of the heatexchanger and the evaporator. The steam produced in each effectcondenses on the colder heat transfer surface of the next effect. Thelast effect 39 consists of the final condenser, which is continuallycooled by the feed water, thus preheating the feed water 1. To improvethe condensing recovery, the feed water can be cooled by air coolersbefore being introduced into the MED (not shown). The feed water maycome from de-oiled produced water, brackish water, water wells or fromany other locally available water source. The brine concentrate 2 isrecycled back to the SD-DCSG in BLOCK 4.

FIG. 11A is a view of the present invention that includes a steamgeneration facility, SD-DCSG and MED water treatment plant. BLOCK 1 is astandard, commercially available steam generation facility forgenerating super heated driving steam 5. The driving steam 5 is fed tothe SD-DCSG in BLOCK 3. Discharged brine from the commercial MEDfacility in BLOCK 2 is also injected into the SD-DCSG 15 and convertedinto steam and solid particles 13. The solids 17 are removed fordisposal. A portion of the generated steam 12 is used to operate the MEDthrough heat exchanger/condenser 28. The condensate 24, after furthertreatment (not shown), is used as BFW. The MED produces distilled BFW 29that is used to produce the driving steam at the boiler 7. The steam 8is injected through injection well 6 for EOR.

FIG. 11B is a schematic diagram of the present invention that includes asteam drive DCSG with a direct heated Multi Stage Flash (MSF) watertreatment plant and a steam boiler for generating steam for EOR. BLOCK 4includes a commercially available steam generation facility. Fuel 2 ismixed with oxidized gas 1 and injected into the steam boiler (acommercially available atmospheric pressure boiler). If a solid-fuelboiler is used, the boiler might include solid waste discharge. Theboiler produces high-pressure steam 5 from distilled BFW 39. The steamis injected into the underground formation through injection well 6 forEOR. A portion of the steam can be used to operate the DCSG. The boilercombustion gas may be cleaned and discharged from stack 3. If naturalgas is used as the fuel 2, there is currently no mandatory requirementin Alberta for further treatment of the discharged flue gas or forremoval of CO2. Steam 9 injected into a pressurized DCSG 15 at anelevated pressure. The DCSG design can be a horizontal sloped rotatingreactor, however any other reactor that can generate a stream of steamand solids can also be used. Solids-rich water 14 that includes thebrine from the MSF is injected into the direct contact steam generator15 where the water evaporates into steam and the solids are carried onwith gas flow 13. The amount of water 14 is controlled to verify thatall the water is converted into steam and that the remaining solids arein a dry form. The solids-rich gas flow 13 flows to a dry solidsseparator 16. The dry solids separator is a commercially availablepackage and it can be used in a variety of gas-solid separation designs.The removed solids 17 are taken to a land-fill for disposal. The steamflows to tower 25. The tower acts like a direct contact heat exchanger.Typically in MSF processes, the feed water is heated in a vessel calledthe brine heater. This is generally done by indirect heat exchange bycondensing the steam on tubes that carry the feed water through thevessel. The heated water then flows to the first stage. In the methoddescribed in FIG. 11B, the feed water of the MSF 45 is heated by directcontact heat exchange 25 (and not through an indirect heat exchanger).The feed water is injected into the up-flowing steam flow 12. The steamcondenses because of heat exchange with the feed water 45. A non-directheat exchanger/condenser can be used as well to heat brine flow 45 withsteam flow 12 while condensing the steam flow 12 to liquid water. In theMSF at BLOCK 30, the heated feed water 46 flows to the first stage 31with a slightly lower pressure, causing it to boil and flash into steam.The amount of flashing is a function of the pressure and the feed watertemperature, which is higher than the saturated water temperature. Theflashing will reduce the temperature to the saturate boilingtemperature. The steam resulting from the flashing water is condensed onheat exchanger 32, where it is cooled by the feed water. The condensatewater 33 is collected and used (after some treatment) 38 as BFW 39 inthe standard, commercially available, steam generation facility 4. Therecan be up to 25 stages. A commercial MSF typically operates in atemperature range of 90-110 C. High temperatures increase efficiency butmay accelerate scale formation and corrosion in the MSF. Efficiency alsodepends on a low condensing temperature at the last stage. The feedwater for the MSF 9 can be treated by adding inhibitors to reduce thescaling and corrosion 38. Those chemicals are available commercially andthe pretreatment package is typically supplied with the MSF. The feedwater is recovered from the produced water in separation unit 10 thatseparates the produced bitumen 8, possibly with diluent that improvesseparation from the water and decreases the viscosity of the heavybitumen. The de-oiled water 9 is supplied to the MSF as feed water.There are several commercially available separation units. In myapplications, the separation, which can be simplified as discharged“oily contaminate water” 18, is allowed in the process. Make-up water29, like water from water wells or from any other water source, iscontinually added to the system. Any type of vacuum pump or ejector canbe used to remove gas 36 and generate the low pressure required in theMSF design.

FIG. 12 is an illustration of the use of a partial combustion gasifierwith the present invention for the production of syngas for use in steamgeneration, a SD-DCSG, and a DCSG combined with a water distillationfacility for ZLD. The system contains few a commercially availableblocks, each of which includes a commercially available facility:

-   -   BLOCK 1 includes the gasifier that produces syngas.    -   BLOCK 2 includes a commercially available steam generation        boiler that is capable of combusting syngas.    -   BLOCK 3 includes a commercially available thermal water        distillation plant.    -   BLOCK 4 includes the SD-DCSG which generates the injection        steam.    -   BLOCK 5 includes a water-oil separation facility with the option        of oily water discharge for recycling into the SD-DCSG.    -   BLOCK 6 includes the DCSG.    -   BLOCK 7 includes a syngas treatment plant where part of the        syngas can be used for hydrogen production etc.

Carbon fuel 5 is injected with oxygen rich 6 gas to a pressurizedgasifier 7. The gasifier shown is a typical Texaco (GE)™ design thatincludes a quenching water bath at the bottom. Any other pressurizedpartial combustion gasifier design can also be used. The gasifier caninclude a heat exchanger, located at the top of the gasifier (near thecombustion section), to recover part of the partial combustion energy togenerate high pressure steam. At the bottom of the gasifier, there is aquenching bath with liquid water to collect solids. Make-up water 13 isthen injected to maintain the liquid bath water level. The quenchingwater 15, which includes the solids generated by the gasifier, isinjected into a DCSG 15 where it is mixed with the produced hot syngasdischarged from the gasifier 12. The DCSG also consumes the liquid waterdischarge 52 from the SD-DCSG 50. In the DCSG, the water is evaporatedinto pressurized steam and solids (which were carried with the water andthe syngas into the DCSG). The DCSG generates a stream of gas and solids16. The solids 19 are removed from the gas flow by a separator 17 fordisposal. The solids lean gas flow 18 (after most of the solids havebeen removed from the gas) is injected into a pressurized wet scrubber20 that removes the solid remains and can also generate saturated steamfrom the heat in gas flow 18. Solids rich water 25 is continuallyrejected from the bottom of the scrubber and recycled back to the DCSG15. Heat 27 is recovered from the saturated water and syngas mixture 21while condensing steam 21 to liquid water 35 and water lean syngas 36.The condensed water 35 can be used as BFW after further treatment toremove contaminations (not shown). The heat 27 is used to operate athermal distillation facility in BLOCK 3. There are several commerciallyavailable facilities for this, such as the MSF or MED. The distillationfacility uses de-oiled produced water 30, possibly with make-up brackishwater 31 and heat 27, to generate a stream of de-mineralized BFW 29 forsteam generation and a stream of brine water 28, with a highconcentration of minerals. The generated brine 28 is recycled back tothe SD-DCSG 50 in BLOCK 4. The syngas can be treated in commerciallyavailable facilities in BLOCK 7 to remove H2S (using amine) or torecover hydrogen. The treated syngas 37, together with oxidizer 38, isused as a fuel source in the commercially available steam generationfacility in BLOCK 2. The super heated steam 40 is generated in steamboiler 39 from the BFW 29. The steam from the boiler 40, possiblytogether with the steam generated by the gasifier 10, is injected intothe SD-DCSG 50 in BLOCK 4 where additional steam is generated from lowquality water 53. The generated steam 51 is injected into an undergroundformation for EOR. The produced bitumen and water recovered fromproduction well 44 are separated in the water-oil separation facility(BLOCK) 5 to produce bitumen 33 and de-oiled water 30. Oily water 34 canbe rejected and consumed in the SD-DCSG 50. By allowing continuousrejection of oily water, the chemical consumption can be reduced and theefficiency of the oil separation unit can be improved.

FIG. 13 is a schematic of the present invention for the generation ofhot water for oilsands mining extraction facilities, with Fine Tailingwater recycling. Block 1A includes a Prior Art commercial open mineoilsands plant. The plant consists of mining oilsands ore and mixing itwith hot process water, typically in a temperature range of 70 C-90 C,separating the bitumen from the water, sand and fines. The cold processwater 8 includes recycled process water together with fresh make-upwater that is supplied from local sources (like the Athabasca River inthe Wood Buffalo area). Another bi-product from the open mine oilsandsplant is Fine Tailings 5 which, after a time, is transferred to a stableMature Fine Tailings. Energy 1 is injected into reactor 3. The energy isin the form of steam gas. The hot, super heated (“dry”) steam gas ismixed in enclosure 3 with a flow of FT 5 from BLOCK 1A. Most of theliquid water in the FT is converted to steam. The remaining solids 4 areremoved in a solid, stable form to use as a back-fill material and tosupport traffic. The produced steam 21 is at a lower temperature thansteam 1 and contains additional water from the FT that was converted tosteam. Steam 1 can be generated by heating the produced steam 21, asdescribed in FIG. 3, 3A or 3B (not shown). The produced steam 21 ismixed with cold process water 8 from BLOCK 1A in a direct contact heatexchanger 7. The produced steam is directly heated and condensed intothe liquid water 8 to generate hot process water 9 that is then suppliedback to operate the Open Mine Oilsands plant 1A. The amount of NCG 2 isminimal. Some NCG can be generated from the organic contaminates in theFT 5. The enclosure 3 system pressure can vary from 103 kpa to 50000 kpaand the temperature at the discharge point 21 can vary from 100 C to 400C.

FIG. 13A is a schematic view of the process for the generation of hotwater for oilsands mining extraction facilities, with Fine Tailing waterrecycling. FIG. 13A is similar to FIG. 13 with the notable differencethat non-direct heat exchange is used between the drive steam 1 and theFT or MFT 5. Block 1A includes a Prior Art commercial open mine oilsandsplant. The plant consists of mining oilsands ore and mixing it with hotprocess water, typically in a temperature range of 70 C-90 C, andseparating the bitumen from the water, sand and fines. The cold processwater 8 includes recycled process water together with fresh make-upwater that is supplied from local sources (like the Athabasca River inthe Wood Buffalo area). Another bi-product from the open mine oilsandsplant is Fine Tailing (FT) 5 which, after a time, are transferred to astable Mature Fine Tailings (MFT). Energy 1 is injected into reactor 3.The energy is in the form of steam gas which is injected aroundenclosure 3 where the heat is transferred to the reactor and to the MFTthrough the enclosure wall. The driving hot steam gas is condensed andrecovered as a liquid condensate 1A. The driving steam 1 heat energy istransferred to the enclosure and used to evaporate the FT 5. Most of theliquid water in the FT is converted to steam. The remaining solids 4 areremoved in a solid/slurry stable form to use as a back-fill materialwhich can support traffic. Steam 1 is generated by a standard boilerheating the condensate 1A in a closed cycle, allowing the use of highquality clean ASME BFW (not shown). The produced steam 21 is mixed withcold process water 8 from BLOCK 1A in a direct contact heat exchanger 7.The produced steam is directly heated and condensed into the liquidwater 8 to generate hot process water 9 that is supplied back to operatethe Open Mine Oilsands plant 1A. The amount of Non Condensable Gases(NCG) 2 is minimal. Some NCG can be generated from the organiccontaminates in the FT 5. The enclosure 3 system pressure can vary from103 kpa to 50000 kpa and the temperature at the discharge point 21 canvary from 100 C to 400 C.

FIG. 13B is a schematic view of the process for the generation of hotwater for oilsands mining extraction facilities, with Fine Tailing waterrecycling. FIG. 13B is similar to FIG. 13A with rotating internals toenhance the heat transfer between the evaporating MFT and the heatsource which is the steam 1 in the enclosure 3. The rotating internalsalso mobilize the high concentration slurry and solids to the soliddischarge 4, where stable material that can support traffic isdischarged from the system. The produced steam 6 is further cleaned toremove solids in commercially available solids separation unit 20 like acyclone, electrostatic filter or any other commercially availablesystem. The generated steam 21 is mixed with cold process water 8supplied from an open mine extraction plant in a direct contact heatexchanger 7. The produced steam is directly heated and condensed intothe liquid water 8 to generate hot process water 9 that is supplied backto operate the extraction Open Mine Oilsands plant.

FIG. 14 is one illustration of the present invention for the generationof pre-heated water that can be used for steam generation or in a miningextraction facility. The invention has full disposal water recycling, soas to achieve zero liquid discharge. Energy 1, in the form of superheated steam, is introduced into the Direct Contact Steam Generatorreactor 3. Contaminated water 5, like FT or MFT, is injected intoreactor 3. There, most of the water is converted into steam, leavingonly solids with a low moisture content. There are several possibilitiesfor the design of reactor 3. The design can be a horizontal rotatingreactor, an up-flow reactor, or any other type of reactor that can beused to generate a stream of solids and gas. A stream of hot gas 6,possibly with carried-on solids generated in reactor 3, flows into acommercially available solid-gas separator 20. Solids 4 can also bedischarged directly from the reactor 3, depending on the type of reactorused. The separated solids 22 and 4 are disposed of in a landfill. Thesolids lean steam flow 21, (rich with steam from flow 5) is condensedinto liquid water 10 in a non-direct condenser 7. There are manycommercially available standard designs for heat-exchanger/condenserthat can be used at 7. The steam heat is used to heat flow 8, likeprocess water flow, to generate hot water 9 that can be used in theextraction process. Low volumes of NCG 2 can be treated or combusted asa heat source (not shown). The condensed liquid water 10 can be used ashot process water for the extraction process or any other usage. Thesteam in flow 21 condenses by non-direct contact with the recycled water8. Solid remains that previously passed through solid separation unit 20and were carried on with the gas flow 21, are washed with the condensedwater 10.

FIG. 15 is a schematic of the invention with an open mine oilsandsextraction facility, where the steam source is a standard gasifier forgenerating steam in a non-direct heat exchange and syngas can be usedfor the production of hydrogen for upgrading the produced crude inprior-art technologies or can be used as a fuel source. The MFT recoveryis done with the steam which was produced by the gasifier and not withthe syngas. The partial combustion of fuel 56 and oxidizer, likeenriched air, takes place inside the gasifier 54. The gasification heatis used to produce superheated steam 55 from BFW 59. The produced syngas60 is recovered and further treated. This treatment can include theremoval of the H2S (like in an amine plant). Treatment can also includegenerating hydrogen for crude oil upgrading or as a fuel source toreplace natural gas usage (not shown). The steam 55 flows to ahorizontal parallel flow DCSG 1. Concentrated MFT 2 is also injectedinto the DCSG. The MFT is converted to gas, mainly steam, and solids 6.The solids 8 are removed in a gas-solid separator 7. The solid leanstream flows through heat exchanger 11, where it heats the processwater, or any other process flow 12, indirectly through a heatexchanger. Condensing hot water 13 is removed from the bottom 11 andused as hot process extraction water. In case NCG 17 is generated, itcan be further treated or combusted as a fuel source. The fine tailings14 are pumped from the tailing pond and can then be separated into twoflows through a specific separation process. Separation 15 is one optionto increase the amount of MFT removal. The process can use natural MFTboth at flows 2 and 16. This separation can be done using a centrifugeor a thickener (like a High Compression Thickener or Chemical PolymerFlocculent based thickener). This unit separates the fine tailings intosolid rich 16 and solid lean 2 flows. The solid lean flow is fed intothe DCSG 1 or recycled and used as the process water (not shown). In theDCSG 1, dry solids are generated and removed from the gas-solidseparator. The solid rich flow 16 is mixed with the dry solids 8 in ascrew conveyor to generate a stable material 27.

FIG. 16 is a schematic of the invention with an open mine oilsandsextraction facility, where the hot process water for the ore preparationis generated by recovering the heat and condensing the steam generatedfrom the fine tailings without the use of a tailings pond. A typicalmine and extraction facility is briefly described in block diagram 1(See “Past, Present and Future Tailings, Tailing Experience at AlbianSands Energy” presentation by J. Matthews from Shell Canada Energy onDec. 8, 2008 at the International Oil Sands Tailings Conference inEdmonton, Alberta). Mined Oil sand feed is transferred via truck to anore preparation facility, where it is crushed in a semi-mobile crusher3. It is also mixed with hot water 57 in a rotary breaker 5. Oversizedparticles are rejected and removed to a landfill. The ore mix goesthrough slurry conditioning, where it is pumped through a specialpipeline 7. Chemicals and air are added to the ore slurry 8. In theinvention, the NCGs 58 that are released under pressure from tower 56can be added to the injected air at 8 to generate aerated slurry flow.The conditioned aerated slurry flow is fed into the bitumen extractionfacility, where it is injected into a Primary Separation Cell 9. Toimprove the separation, the slurry is recycled through floatation cells10. Oversized particles are removed through a screen 12 in the bottom ofthe separation cell. From the flotation cells, the coarse and finetailings are separated in separator 13. The fine tailings flow tothickener 18. To improve the separation in the thickener, flocculant isadded 17. Recycled water 16 is recovered from the thickener and finetailings are removed from the bottom of the thickener 18. The froth isremoved from the Primary Separation Cell 9 to vessel 21. In this vessel,steam 14 is injected to remove air and gas from the froth. The recoveredfroth is maintained in a Froth Storage Tank 23. The coarse tailings 15and the fine tailings 19 are removed and sent to tailing processing area60. The fine and coarse tailings can be combined, or removed and sentseparately (not shown) to the tailing process area 60. In Unit 60, thesand and other large solid particles are removed and then put back intothe mine, or stored in stock-piles. Liquid flow is separated into 3different flows, mostly differing in their solids concentration. Arelatively solids-free flow 62 is heated. This flow is used as heatedprocess water 57 in the ore preparation facility, for generation of theoilsands slurry 6. The fine tailings stream can be separated into twosub streams. The most concentrated fine tailings 51 are mixed with drysolids, generated by the DCSG, to generate a solid and stable substratematerial that can be put back into the mine and used to support traffic.The medium concentration fine tailing stream 61 flows to the DCSGfacility 50. Steam energy 47 is used in the DCSG to convert the finetailings 61 water into a dry or semi dry solid and gas stream. The steamcan be produced in a standard high pressure steam boiler 40, in an OTSG,or produced by a COGEN, using the elevated temperature in a gas turbinetail (not shown). The boiler consumes fuel gas 38 and air 39 whilegenerating steam 14. A portion 47 of the generated steam 14 can beinjected into the DCSG 50. The temperature of the DCSG produced steamcan vary from 100 C to 400 C as it includes the water from the MFT.Steam 47 can be also generated by heating a portion of the producedsteam 52 as described in FIGS. 3, 3A and 3B. The solids are separatedfrom the gas stream in any commercially available facility 45 which caninclude: cyclone separators, centrifugal separators, mesh separators,electrostatic separators or other combination technologies. The solidslean steam 52 flows into tower 56. The gas flows up into the tower,possibly through a set of trays, while any solid carried-on remnants arescrubbed from the up flowing gas through direct contact with liquidwater. The water vapor that was generated from heating the fine tailing61 in the DCSG and the steam that provided the energy to evaporate theFT are condensed and added to the down-flowing extraction water process57. The presence of small amounts of remaining solids in the hot processwater is acceptable. That is because the hot water is mixed with thecrushed oilsands 3 in the breaker during ore preparation. Thetemperature of the discharged hot water 57 is between 70 C and 95 C,typically in the 80 C-90 C range. The hot water is supplied to the orepreparation facility. The separated dry solids from the DCSG are mixedwith the concentrated slurry flow from the tailing water separationfacility 60. They are used to generate a stable solid waste that can bereturned to the oilsands mine for back-fill and can be used to supporttraffic. Any commercially available mixing method can be used in theprocess: a rotating mixer, a Z type mixer, a screw mixer, an extruder orany other commercially available mixer. The slurry 51 can be pumped tothe mixing location, while the dry solids can be transportedpneumatically to the mixing location. The described arrangement, wherethe fine tailings are separated into two streams 61 and 51, is intendedto maximize the potential of the process to recover MFT. It is meant tomaximize the conversion of fine tailings into solid waste for each unitweight of the supplied fuel source. The system can work in the mannerdescribed for tailing pond water recovery. The tailing pond water iscondensed in hot water generation 57, without the combination of the drysolids 53 and tailing slurry 51. The generated dry solids 53 are a“water starving” dry material. As such, they are effective in theprocess of drying MFT to generate trafficable solid material withoutrelying on weather conditions to dry excess water.

FIG. 17 is a schematic of the invention with an open mine oilsandextraction facility, where the hot process water for the ore preparationis generated from condensing the steam produced from the fine tailings.A typical mine and extraction facility is briefly described in blockdiagram 1. The tailing water from the oilsands mine facility 1 isdisposed of in a tailing pond. The tailing ponds are designed in such away that the sand tailings are used to build the containment areas forthe fine tailings. The tailings are generated in the Extraction Process.They include the cyclone underflow tailings 13 (mainly coarse tailings)and the fine tailings from the thickener 18, where flocculants are addedto enhance the solid settling and recycling of warm water. Anothersource of fine tailings is the Froth Treatment Tailings, where thetailings are discarded using the solvent recovery process; the FrothTreatment Tailings are characterized by high fines content, relativelyhigh asphaltene content, and residual solvent. (See “Past, Present andFuture Tailings, Tailing Experience at Albian Sands Energy” apresentation by J. Matthews from Shell Canada Energy on Dec. 8, 2008 atthe International Oil Sands Tailings Conference in Edmonton, Alberta). Asand dyke 55 contains a tailing pond. The sand separates from thetailings and generates a sand beach 56. Fine tailings 57 are put abovethe sand beach at the middle-low section of the tailing pond. Some finetailings are trapped in the sand beach 56. On top of the fine tailing isthe recycled water layer 58. The tailing concentration increases withdepth. Close to the bottom of the tailing layer are the MFT (Mature FineTailings). (See “The Chemistry of Oil Sands Tailings: Production toTreatment” presentation by R. J. Mikula, V. A. Munoz, O. E. Omotoso, andK. L. Kasperski of CanmetENERGY, Devon, Alberta, Natural ResourcesCanada on Dec. 8, 2008 at the International Oil Sands TailingsConference in Edmonton, Alberta). The recycled water 41 is pumped from alocation close to the surface of the tailing pond (typically from afloating barge). The fine tailings that are used for generating steamand solid waste in my invention are the MFT. They are pumped from thedeep areas of the fine tailings 43. Steam 48 is injected into a DCSG.MFT 43 are pumped from the lower section of the tailing pond and arethen directed to the DCSG 50. The DCSG described in this particularexample is a horizontal, counter flow rotating DCSG. However, anyavailable DCSG that can generate gas and solids from the MFT can be usedas well. Due to the heat and pressure inside the DCSG, the MFT turn intogas and solids as the water is converted into steam. The solids arerecovered in a dry form or in a semi-dry, semi-solid slurry form 51. Thesemi-dry slurry form is stable enough to be sent back into the oilsandsmine without the need for further drying and can be used to supporttraffic. The produced steam 14, of which portion 48 can be used tooperate the DCSG, is generated by a standard steam generation facility36 from BFW 37, fuel gas 38 and air 39. The blow-down water 20 can berecycled into the process water 20. By continually consuming the finetailing water 43, the oil sand mine facility can use a much smallertailing pond as a means of separating the recycled water from the finetailings. This smaller recyclable tailing pond is cost effective, and isa simple way to deal with tailings as it does not involve any movingparts (in contrast to the centrifuge or to thickening facilities). Thissolution will allow for the creation of a sustainable, fully recyclablewater solution for the open mine oilsands facilities. Steam 48 can begenerated by heating a portion of the produced steam 47, as described inFIGS. 3, 3A and 3B.

FIG. 18 is a schematic of the invention with open mine oilsandsextraction facility, where the hot process water for the ore preparationis generated by condensing the steam generated from the fine tailingsand the driving steam. The tailing water from the oilsands mine facility43 (not shown) is disposed of in a tailing pond. Steam 4 is fed into ahorizontal parallel flow DCSG 1. Concentrated MFT 2 is injected into theDCSG 1 as well. The MFT is converted into steam, and solids. The solidsare removed in a solid-gas separator 7 where the solid lean stream iswashed in tower 10 by saturated water. In the tower, the solids arewashed out and then removed. The solid rich discharge flow 13 can berecycled back to the DCSG or to the tailing pond. Heat is recovered fromthe saturated steam 16 in heat exchanger/condenser 17. Steam iscondensed to water 20. The condensed water 20 can be used as hot processwater and can be added to the flow 24. The recovered heat is used forheating the process water 35. The fine tailings 32 are pumped from thetailing pond and separated into two flows by a centrifugal process 31.This unit separates the fine tailings into two components: solid rich 30and solid lean 33 flows. The centrifuge unit described is commerciallyavailable and was tested successfully in two field pilots (See “ThePast, Present and Future of Tailings at Syncrude” presentation by A.Fair from Syncrude on Dec. 7-10, 2008 at the International Oil SandsTailings Conference in Edmonton, Alberta). Other processes, likethickening the MFT with chemical polymer flocculent, can be used as wellinstead of the centrifuge. The solid lean flow can contain less than 1%solids. The solid rich flow is a thick slurry (“cake”) that containsmore than 60% solids. The solid lean flow is used directly or isrecycled back to a settling basin (not shown) and is eventually used asprocess water 35. The solid concentration is not dry enough to bedisposed of efficiently and cannot be used to support traffic. This canbe solved by mixing it with a “water starving” material (virtually drysolids generated by the DCSG). Mixing of the dry solids and the thickslurry can be achieved through many commercially available methods. Inthis particular figure, the mixing is done by a screw conveyer 29 wherethe slurry 30 and the dry material 8 are added to the bottom of a screwconveyor, mixed by the screw, and then the stable solids are loaded on atruck 28 for disposal. The produced solid material 27 can be backfilledinto the oilsands mine excavation site and then used to support traffic.It is also possible to feed the thickened MFT directly to the DCSG 1,eliminating the additional mixing process. In this particular figure,there are two options for supplying the fine tailing water to the DCSG:one is to supply the solid rich thick slurry 30 from the centrifuge orthickening unit 31. The other is to use the “conventional” MFT,typically with 30% solids, pumped from the settlement pond. Feeding theMFT “as is” to the DCSG eliminates the TIC, operation, and maintenancecosts for a centrifuge or thickening facility.

FIG. 19 is an illustration of one embodiment of the present invention.Fuel 2 is mixed with oxidizing gas 1 and injected into the steam boiler4. The boiler is a commercially available atmospheric pressure boiler.If a solid fuel boiler is used, the boiler might include a solid wastedischarge. The boiler produces high-pressure steam 5 from distilled BFW19. The steam is injected into the underground formation throughinjection well 6 for EOR. The boiler combustion gases are possiblycleaned and discharged from stack 32. If natural gas is used as the fuel2, there is currently no mandatory requirement in Alberta to furthertreat the discharged flue gas or remove CO2. Steam 9 is injected into apressurized DCSG 15 at an elevated pressure. The DCSG design can includea horizontal rotating reactor, a fluidized bed reactor, an up-flowreactor, or any other reactor that can be used to generate a stream ofgas and solids. Solids-rich water 14 is injected into the direct contactsteam generator 15 where the water evaporates into steam and the solidsare carried on with gas flow 13. The amount of water 14 is controlled inorder to verify that all the water is converted into steam and that theremaining solids are in a dry form. The solid-rich gas 13 flows to a drysolids separator 16. The dry solids separator is a commerciallyavailable package and it can be used in a variety of gas-solidseparation designs. The solids 17 are taken to a land-fill. The solidslean flow 12 flows to the heat exchanger 30. The steam continuallycondenses because of heat exchange. Heat 25 is recovered from gas flow12. The condensed water 36 can be used for steam generation. Thecondensation heat 25 can be used to operate the distillation unit 11.The distillation unit 11 produces distillation water 19. The brine water26 is recycled back to the direct contact steam generator 15 where theliquid water is converted to steam and the dissolved solids remain in adry form. The distillation unit 11 receives de-oiled produced water 39that is separated in a commercially available separation facility 10,like that which is currently in use by the industry. Additional make-upwater 34 is added. This water can be brackish water, from deepunderground formations, or from any other water source that is locallyavailable to the oil producers. The quality of the make-up water 34 issuitable for the distillation facility 11, where there are typicallyvery low levels of organics due to their tendency to damage theevaporator's performance or carry on and damage the boiler. Water thatcontains organics is a by-product of the separation unit 10 and it willbe used in the DCSG 15. By integrating the separation unit 10 and theDCSG 15, the organic contaminated by-product water can be used directly,without any additional treatment by the DCSG 15. This simplifies theseparation facility 10 so that it can reject contaminated water withoutenvironmental impact. It is sent to the DCSG 15, where most of theorganics are converted into hydrocarbon gas phase or are carbonic withthe hot steam gas flow. The distilled water 19 produced by thedistillation facility 11, possibly with the condensed steam from flow12, are sent to the commercially available, non-direct, steam generator4. The produced steam 5 is injected into an underground formation forEOR. The brine 26 is recycled back 14 to the DCSG and solids dryer 15 asdescribed before. The production well 7 produces a mixture of tar, waterand other contaminants. The oil and water are separated in commerciallyavailable plants 10 into water 9 and oil product 8.

FIG. 20 is an illustration of one embodiment of the present invention.It is similar to FIG. 19 with the following modifications describedbelow: The solids lean flow 12 is mixed with saturated water 21 invessel 20. The heat carried in the steam gas 12 can generate additionalsteam if its temperature is higher than the saturated water 21temperature. The solids carried with the steam gas are washed bysaturated liquid water 23. The solids rich water 24 is discharged fromthe bottom of the vessel 20 and recycled back to the DCSG 15 where theliquid water is converted into steam and the solids are removed in a dryform for disposal. Saturated “wet” solids free steam 22 flows to heatexchanger/condenser 30. The condensed water 36 is used for steamgeneration. The condensation heat 25 is used to operate a watertreatment plant 11, as described in FIG. 19 above. To minimize theamount of steam 9 used to drive the DCSG 15, it is possible to recycle aportion of the produced saturated steam 22 as described in FIGS. 3, 3Aand 3B. This option is shown as the dotted line. A portion of theproduced steam 22 is recycled to drive the process. This steam iscompressed 42 to allow the flow to be recycled and to overcome theheater and the SD-DCSG pressure drop. The steam is heated in anon-direct heat exchanger 41. Any type of heat exchanger/heater can beused at 41. One example is the use of a typical re-heater 43 that ispart of a standard boiler design.

FIG. 21 is an illustration of a boiler, steam drive DCSG, solid removaland Mechanical Vapor Compression distillation facility for generatingdistilled water in the boiler for steam generation for EOR. BLOCK 4includes a steam generation unit. Fuel 2, possibly with water in aslurry form, is mixed with air 1 and injected into a steam boiler 4. Theboiler may have waste discharged from the bottom of the combustionchamber. The boiler produces high-pressure steam 3 from treateddistillate feed water 5. The steam is injected into the undergroundformation through injection well 21 for EOR. Part of the steam 7 isdirected to drive a DCSG 9. BLOCK 22 includes a steam drive DCSG 9.Solids rich water, like concentrated brine 8 from the distillationfacility, is injected into the DCSG 9 where the water is mixed withsuper heated steam 7. The liquid water phase is converted to steam dueto the high temperature of the driving steam 7. The DCSG can be acommercially available direct-contact rotary dryer or any other type ofdirect contact dryer capable of generating solid waste and steam fromsolid-rich brine water 8. The DCSG generates a stream of steam 10 withsolid particles from the solid rich water 8. The DCSG in BLOCK 22 cangenerate its own driving steam 7 by recycling and heating a portion ofthe saturated produced steam 12, as described in FIGS. 3, 3A and 3B (notshown). The amount of water 8 is controlled to verify that all the wateris converted into steam and that the remaining solids are in a dry form.The solid-rich steam gas flow 10 is directed to BLOCK 21 which separatesthe solids. The solids separation is in a dry solids separator 12. Thedry solids separator is a commercially available package and it can beused in a variety of gas-solid separation designs. The solids lean flow11 is mixed with saturated water 22 in a direct contact wash vessel 15.The solid remains carried with the steam are washed by saturated liquidwater 22. The solids rich water 14 is discharged from the bottom of thevessel 22 and recycled back to dryer 9 where the liquid water isconverted into steam and the solids are removed in a dry form fordisposal. If the dry solid removal efficiency at 12 is high, it ispossible to eliminate the use of the saturate water liquid scrubber 15.The produced saturated steam 23 is supplied to BLOCK 20, which is acommercially available distillation unit that produces distillationwater 5. The brine water 8 is recycled back to the direct contact steamgenerator/solids dryer 15 where the liquid water is converted into steamand the dissolved solids remain in dry form. Distillation unit 19 is aMechanical Vapor Compression (MVC) distillation facility. It receivesde-oiled produced water 16 that has been separated in a commerciallyavailable separation facility (such as that currently in use by theindustry) with additional make-up water (not shown). This water can bebrackish, from deep underground formations or from any other watersource that is locally available to the oil producers. The quality ofthe make-up water is suitable for the distillation facility 20, wherethere are typically very low levels of organics due to their tendency todamage the evaporator's performance or damage the boiler further in theprocess. The distilled water produced by distillation facility 19 istreated by the distillate treatment unit 17, typically supplied as partof the MVC distillation package. The treated distilled water 5 can beused in the boiler to produce 100% quality steam for EOR. The brine 8and possibly the scrubbing water 14 are recycled back to the DCSG/dryer9 as previously described. The heat from flow 23 is used to operate thedistillation unit in Block 20. The condensing steam from flow 23 isrecovered in the form of liquid distilled water 5. The high-pressuresteam from the boiler in BLOCK 4 is injected into the injection well 21for EOR or for other uses (not shown). With the use of a low pressuresystem (which includes a low pressure dryer), the thermal efficiency ofthe system is lower than using a high pressurized system withpressurized DCSG.

The following are examples for heat and material balance simulations:

Example 1

The graph in FIG. 22 simulates the process as described in FIG. 2A. Thesystem pressure was constant at 25 bar. The liquid water 7 was attemperature of 25 C with a constant flow of 1000 kg/hour. The product 8was saturated steam at 25 bar. The graph below shows the amount of drivesteam 9 required to transfer the liquid water 7 into the gas phase as afunction of the temperature of the driving steam 9. When 300 C drivingsteam is used, there is a need for 12.9 ton/hour of steam 9 to gasifyone ton/hour of liquid water 7. When 500 C driving steam is used, thereis a need for only 4.1 ton/hour of steam 9 to gasify one ton/hour ofliquid water 7. The following are the results of the simulation:

Drive Steam 9 Drive Steam 9 Temperature(° C.) Flow (kg/hr) 600.003059.20 550.00 3502.50 500.00 4091.50 450.00 4914.46 400.00 6159.21350.00 8290.00 300.00 12990.00 250.00 34950.00

Example 2

The graph in FIG. 23 simulates the process as described in FIG. 2A. Thedriving steam 9 temperature was constant at 450° C. The liquid water 7was at temperature of 25° C. and had a constant flow of 1000 kg/hour.The produced steam product 8 was saturated. The graph shows the amountof drive steam 9 required to transfer the liquid water 7 into the gasphase as a function of the pressure of the driving steam 9. When thesystem pressure was 2 bar, 3.87 tons/hour of driving steam was needed toconvert the water to saturated steam at temperature of 121° C. For a 50bar system pressure, 5.14 tons/hour of driving steam was used togenerate saturated steam at 256° C. The simulation results aresummarized in the following table:

Temperature Driving System of Saturated Steam Pressure produced Flow(bar) Steam (kg/hr) 100.00 311.82 5127.94 75.00 291.35 5161.78 50.00264.74 5135.66 25.00 224.70 4914.46 20.00 213.11 4821.42 15.00 198.984696.41 10.00 180.53 4515.83 5.00 152.40 4218.44 3.00 134.03 4018.9922.00 120.68 3870.57 1.00 100.00 3649.728

Example 3

The graph in FIG. 24 simulates the process as described in FIG. 2A wherethe water feed includes solids and naphtha. As the pressure increases,the saturated temperature of the steam also increases from around 100 Cat 1 bar to around 312 C 100 bar. Thus, the amount of superheated steaminput at 450 C also increases from around 2300 kg/hr to 4055 kg/hr. Thegraph in FIG. 24 represents the superheated driving steam input 9 andthe total flow rate (including hydrocarbons) of the produced gas 8.

Flow Number 7 9 12 8 T, C 25.00 450.00 120.61 120.61 P, atm 2.00 2.002.00 2.00 Vapor Fraction 0.00 1.00 0.00 1.00 Enthalpy, MJ −14885.08−29133.36 −6692.49 −37325.62 Total Flow, kg/hr 1000.00 2311.54 414.732896.81 Water 600.00 2311.54 114.20 2797.34 Solids 300.00 0.00 300.004.14E−17 Naptha 100.00 0.00 0.53 99.47

Example 4

The following table simulates the process as described in FIG. 3 forinsitue oilsands thermal extraction facilities, like SAGD, for twodifferent pressures. The water feed is hot produced water at 200 C thatincludes solids and bitumen. The heat source Q′ for the simulation was12 KW.

For a system pressure of 400 psi the total Inflow of water, solids andbitumen of flow 34 was 23.4 kg. 77% of the steam 31 is recycled as thedriving steam 32 while 23% is discharged out of system at 283 C steamand hydrocarbons.

For a system pressure of 600 psi, the total Inflow of water, solids, andBitumen of flow 34 was 22.5 kg. 80% of the steam 31 is recycled as thedriving steam 32 while 20% is discharged out of system at 283 C steamand hydrocarbons.

Flow Number 34 35 31 32 36 33 T, C. 200 243.42 243.42 243.43 486.73243.43 Press., psig 400 400 400 400 400.00 400.00 Vapor Fraction 0 0.001.00 1.00 1.00 1.00 Enthalpy, kW −96.591 −5.06 −346.24 −266.80 −254.78−79.69 Total Flow, kg/hr 23.4 1.17 96.89 74.66 74.66 22.30 Water, kg/hr21.76 0.00 94.84 73.08 73.08 21.83 Solids 1.17 1.17 0.00 0.00 0.00 0.00Hydrocarbons 0.470 0.000 2.048 1.578 1.578 0.471 T, C. 200 282.88 282.88282.62 485.97 282.62 Press., psig 600 600.00 600.00 600.00 600.00 600.00Vapor Fraction 0 0.00 1.00 1.00 1.00 1.00 Enthalpy, kW −92.863 −4.78−381.06 −305.04 −293.02 −76.26 Total Flow, kg/hr 22.5 1.12 107.11 85.7485.74 21.43 Water, kg/hr 20.925 0.00 104.86 83.93 83.93 20.98 Solids1.125 1.12 0.00 0.00 0.00 0.00 Bitumen 0.450 0.000 2.255 1.805 1.8050.451

Example 5

The following process simulation described in FIG. 30 simulates a 600psi system pressure. The graph in FIG. 30 simulates the impact of theproduced water feed temperature on the overall process performance. Hotproduced water that includes solids and bitumen contaminates is typicalfor insitue oilsands thermal extraction facilities like SAGD. The graphshows that for a constant heat flow, as the produced feed watertemperature increases, the amount of produced steam increasesaccordingly. The heat source Q′ in the simulation was 12 KW. The drivingsteam 36 temperature was 482 C. 80% of the steam 31 is recycled to theheater as the driving steam 36 while 20% is discharged out of system at283 C steam and hydrocarbons. The simulation shows that for feed waterat a temperature of 20 C, 15.1 kg of produced steam is generated. For atemperature of 100 C, 17.4 kg of produced steam is produced and for atemperature of 220 C, 22.4 kg of produced steam is produced.

Example 6

The following table simulates the process as described in FIG. 4 forinsitue oilsands thermal extraction facilities like SAGD. The water feedis hot produced water at 200 C that includes solids and bitumen. Theheat source Q′ for the simulation was 12 KW and the system pressure was600 psi. The total Inflow of water, solids, and bitumen of flow 47 was22.5 kg. 79% of the steam 31 is recycled as the driving steam 36 while21% is discharged out of system at 294 C steam and hydrocarbons.

In the simulation, 4.9 kw were removed at the flash/condensation unit 42and used to pre-heat the water feed 47. The product was split from flow31 (not shown on FIG. 4) replacing flow 46. Flows 44 and 45 were equalin this simulation.

Product Flow Number (split 47 35 31 33 36 45 43 from 33) T, C. 200294.91 294.91 294.91 471.55 253.81 253.81 294.91 Press., psig 600 600.00600.00 600.00 600.00 600.00 600.00 600.00 Vapor Fraction 0 0.00 1.001.00 1.00 1.00 0.13 1.00 Enthalpy, kW −92.863 −4.76 −361.07 −285.24−261.99 −274.01 −15.89 −75.82 Total Flow, 22.5 1.13 101.76 80.39 74.8274.82 5.56 21.37 kg/hr Water, kg/hr 20.925 0.00 99.64 78.72 74.82 74.823.90 20.92 SiO2 1.125 1.13 0.00 0.00 0.00 0.00 0.00 0.00 hydrocarbons0.450 0.000 2.118 1.673 0.000 0.000 1.668 0.445

Example 7

The following table is the simulation results for the process describedin FIG. 25. The water feed 1 is produced water from a SAGD separator andincludes solids and hydrocarbons at a temperature of 200 C. The producedwater 1 is mixed with superheated steam 7 at approximately 482 C.Recycled water 12 from scrubber 23 is recycled back to the water feed 1.Solid contaminates 3 are removed from separator 21. The produced steam 4is divided into two flows—portion 6 of the produced steam (22%) at atemperature of 285 C and pressure of 600 psi is recovered from thesystem as the product for steam injection, or any other use. Theremaining 78% of the produced steam 5 is cleaned in a wet scrubber withsaturated water, potentially with additional chemicals that canefficiently removed silica and possibly other contaminates that wereintroduced with the produced water (like magnesium based additives, sodacaustic, and others). Water 9 is fed into the scrubber 23 and thescrubbed water 12 is continually recycled back to the stage of steamgeneration. The scrubbed steam 8 is compressed by mechanical means or bysteam ejector 24 to a heater 25. In the simulation, a 12 kw heater wasused 25 to simulate a bench scale laboratory facility. In a commercialplant any heater can be used. The system simulation pressure was 600psig. The superheated steam 7 is used as the driving steam to drive theprocess.

Flow Number 1 2 3 4 5 6 T, C. 200 284.78 284.78 284.78 284.77 284.77Press., psig 600 600 600 600 600 600 Vapor Fraction 0 1 0 1 1 1Enthalpy, kW −74.29 −330.8 −3.82 −326.94 −255.03 −71.93 Total Flow,kg/hr 18 92.53 0.9 91.63 71.47 20.16 Water, kg/hr 16.74 90.01 0 90.0170.21 19.8 Solids 0.9 0.9 0.9 0 0 0 Hydrocarbons 0.36 1.618 0 1.6181.262 0.356 Flow Number 7 8 9 10 12 T, C. 478.12 253.81 20 254.13 253.81Press., psig 600 600 600 601.46 600 Vapor Fraction 1 1 0 1 0 Enthalpy,kW −255.05 −267.08 −13.25 −267.04 −1.21 Total Flow, kg/hr 72.92 72.93 372.92 1.55 Water, kg/hr 72.92 72.93 3 72.92 0.28 Solids 0 0 0 0 0Hydrocarbons 0 0 0 6.99E−06 1.262

Another option to minimize the risk of build-ups in the injection pipingis to recover the produced steam 6 from flow 8 (indicated on FIG. 25 asflow 6A). This option was simulated as described in the table below. Inreality, flow 6A will be cleaner than flow 6, because the steam will bescrubbed by saturated liquid water 9. The scrubbing water 9 can includechemical to remove contaminates, like silica, from the produced steam 4.The simulation shows that this option do not affect the overall processefficiency. The size of scrubbing vessel 23 will increase with theincreased flow.

Flow Number 1 2 3 4 5 6A T, C. 200 267.16 267.16 267.16 267.16 253.81Press., psig 600 600.00 600.00 600.00 600.00 600.00 Vapor Fraction 00.99 0.00 1.00 1.00 1.00 Enthalpy, kW −75.7649 −340.01 −3.93 −336.03−336.03 −76.38 Total Flow, kg/hr 18.36 96.85 0.92 95.93 95.93 20.86Water, kg/hr 17.07 92.08 0.00 92.08 92.08 20.86 Solids 0.92 0.92 0.920.00 0.00 0.00 Hydrocarbons 0.370 3.848 0.000 3.848 3.848 0.000 FlowNumber 7 8 9 10 12 T, C. 481.86 253.81 20.00 254.1276 253.81 Press.,psig 600.00 600.00 600.00 601.4696 600.00 Vapor Fraction 1.00 1.00 0.001 0.00 Enthalpy, kW −251.25 −263.09 −15.46 −263.249 −12.00 Total Flow,kg/hr 71.89 71.84 3.50 71.88519 6.73 Water, kg/hr 71.89 71.84 3.5071.88519 2.88 Solids 0.00 0.00 0.00 0 0.00 Hydrocarbons 0.000 0.0000.000 3.17E−06 3.848

Example 8

The following table are the simulation results for the process describedin FIG. 26. The water feed 1 is produced water from a SAGD separator andincludes solids and hydrocarbons at a high temperature of 200 C. (Theproduced water 1 is at a much lower flow of approx. 8 kg/hour comparedto the flow of 18 kg/hour in example 25 because additional treatedboiler feed water 10 is added later). The feed 1 is mixed withsuperheated steam 7 at approximately 482 C. Recycled water 12 fromscrubber 23 is recycled back to the water feed 1. Solid contaminates 3are removed from separator 21. The produced steam 4 is divided into twoflows—portion 6 of the produced steam (75%) at a temperature of 271 Cand pressure of 600 psi is recovered from the system as the product forsteam injection in CSS, SAGD or any other steam use. Another option thatwasn't simulated is to clean and scrub all the produced steam 4 togenerate a cleaner produced steam for injection 6A. This option can beused in case contaminates in the produced steam 4 can damage theinjection facility or block the formation over time. The remaining 25%of the produced steam 5 is cleaned in a wet scrubber with saturatedwater, potentially with additional chemicals to remove contaminates.Water 9 with a flow rate of 0.3 kg/hour and temperature of 20 C is fedinto the scrubber 23 and the scrubbed water 12 is continually recycledback to the stage of the steam generation. The scrubbed steam 8 iscondensed by direct contact with clean BFW 10 at a flow of 10 kg/hourand temperature of 20 C. The generated water 11 at a temperature of 250C is pumped to low overpressure to generate circulation and compensatefor the losses and is then transferred into superheated steam by a 12 kwheater 25 to simulate a bench scale laboratory facility. In a commercialplant any commercial boiler can be used to produce the superheated drysteam. The system simulation pressure was 600 psig. The superheatedsteam 7 at a flow of 16 kg/hour is used as the driving steam to drivethe process.

Flow No. 1 2 3 4 5 6 T, C. 200.00 271.89 271.89 271.89 271.88 271.88Press., psig 600.00 600.00 600.00 600.00 600.00 600.00 Vapor Fraction0.00 0.99 0.00 1.00 1.00 1.00 Enthalpy, kW −32.47 −87.32 −1.66 −85.64−21.42 −64.27 Total Flow, 7.870 24.105 0.390 23.715 5.932 17.797 kg/hrWater, kg/hr 7.320 23.500 0.000 23.500 5.879 17.636 Solids 0.390 0.3900.390 0.000 0.000 0.000 Hydrocarbons 0.160 0.215 0.000 0.215 0.054 0.161Flow No. 7 8 9 10 11 12 T, C. 660.37 253.81 20.00 20.00 250.31 253.81Press., psig 600.00 600.00 600.00 600.00 600.00 600.00 Vapor Fraction1.00 1.00 0.00 0.00 0.00 0.00 Enthalpy, kW −53.87 −21.71 −1.32 −44.16−65.87 −1.04 Total Flow, 15.927 5.927 0.300 10.000 15.927 0.305 kg/hrWater, kg/hr 15.927 5.927 0.300 10.000 15.927 0.251 Solids 0.000 0.0000.000 0.000 0.000 0.000 Hydrocarbons 0.000 0.000 0.000 0.000 0.000 0.054To minimize the risk of build-ups in the downstream piping and equipmentit is possible to recover the produced steam 6 from flow 8 (indicated onFIG. 25 as flow 6A). The following table are the simulation results forthe process described in FIG. 26 with flow 6A as the produced steamexported from the system. The produced steam 6A is extracted from steamflow 8 after scrubbing in vessel 23 with water 9. Additional chemicalcan be added to the scrubbing water 9 to remove contaminates with stream4.

Flow No. 1 2 3 4 5 6A T, C. 200.00 253.81 253.81 253.81 253.81 253.81Press., psig 600.00 600.00 600.00 600.00 600.00 600.00 Vapor 0.00 0.890.00 0.95 0.95 1.00 Fraction Enthalpy, −32.47 −104.51 −1.67 −102.07−102.07 −71.18 kW Total Flow, 7.870 28.770 0.390 28.380 28.380 19.436kg/hr Water, kg/hr 7.320 27.686 0.000 27.686 27.686 19.436 Solids 0.3900.390 0.390 0.000 0.000 0.000 Hydro- 0.160 0.695 0.000 0.695 0.695 0.000carbons Flow No. 7 8 9 10 11 12 T, C. 482.16 253.81 20.00 20.00 239.99253.81 Press., psig 600.00 600.00 600.00 600.00 600.00 600.00 Vapor 1.001.00 0.00 0.00 0.00 0.00 Fraction Enthalpy, −64.08 −23.73 −2.65 −52.3303−76.06 −9.81 kW Total Flow, 18.335 6.479 0.600 11.850 18.330 3.065 kg/hrWater, kg/hr 18.335 6.479 0.600 11.850 18.330 2.370 Solids 0.000 0.0000.000 0.000 0.000 0.000 Hydro- 0.000 0.000 0.000 0.000 0.000 0.695carbons

Example 9

The following table are the simulation results for the process describedin FIG. 27. The simulation is similar to Example 8 with a change to theproduction of the boiler feed water where instead of using clean BoilerFeed water to condense the generated steam for generating thesuperheated steam generator feed water, heat is recovered to condensethe steam to BFW and is introduced back to the system to heat the feedwater. By this arrangement, the need for fresh BFW is eliminated andreplaced by condensation. Water feed 1 is heated with Q-in, that is aheat recovered from the condensation, and mixed with superheated steam7. Recycled water 12 from scrubber 23 is recycled back to the water feed1. Solid contaminates 3 are removed from separator 21. The producedsteam 4 is divided into two flows—portion 6 of the produced steam (53%)at a temperature of 282 C and pressure of 600 psi is recovered from thesystem as the product for steam injection or any other use. Theremaining 47% of the produced steam 5 is cleaned in a wet scrubber withsaturated water, potentially with additional chemicals to removecontaminates. Water 9 at a flow of 4.1 kg/hour and temperature of 20 Cis fed into the scrubber 23 and the scrubbed water 12 is continuallyrecycled back to the stage of the steam generation. The scrubbed cleansteam 8 is condensed by recovering the condensation heat Q-out that isreturned back to the system for pre-heating the feed water as Q-in orfor pre-heating other streams like 9. The generated water 11, at atemperature of 254 C, is pumped to low overpressure to generatecirculation and compensate for the losses and is then generated intosuperheated steam by a 12 kw heater 25 to simulate a bench scalelaboratory facility. In a commercial plant, any commercial boiler can beused to produce the superheated dry steam. The system simulationpressure was 600 psig. The superheated steam 7 at a flow of 18.7 kg/houris used as the driving steam to drive the process. Another option tominimize the risk of build-ups in the injection piping is to recover theproduced steam 6 from flow 8 (indicated on FIG. 25 as flow 6A).

Flow No. 1 2 3 4 5 6 T, C. 200.00 282.56 282.56 282.56 282.52 282.52Press., 600.00 600.00 600.00 600.00 600.00 600.00 psig Vapor 0.00 0.990.00 1.00 1.00 1.00 Fraction Enthalpy, −86.378 −145.07 −4.46 −140.57−66.07 −74.51 kW Total 20.930 40.518 1.050 39.468 18.552 20.920 Flow,kg/hr Water, 19.460 38.678 0.000 38.678 18.180 20.501 kg/hr Solids 1.0501.050 1.050 0.000 0.000 0.000 Hydro- 0.420 0.791 0.000 0.791 0.372 0.419carbons Flow No. 7 8 9 11 12 T, C. 493.17 253.81 20.00 253.81 253.81Press., psig 600.00 600.00 600.00 600.00 600.00 Vapor Fraction 1.00 1.000.00 0.00 0.00 Enthalpy, kW −65.12 −68.38 −4.42 −77.12 −2.11 Total Flow,18.671 18.671 1.000 18.671 0.881 kg/hr Water, kg/hr 18.671 18.671 1.00018.671 0.509 Solids 0.000 0.000 0.000 0.000 0.000 Hydrocarbons 0.0000.000 0.000 0.000 0.372

Example 10

The following table are the simulation results for the process describedin FIG. 28. The water feed 1 is tailings water from an open mineoilsands extraction facility. The feed water includes 30% solids and 3%solvents at a temperature of 20 C. The system is at a low pressure,close to atmospheric pressure. The produced water 1 is mixed withsuperheated steam 7 at 535 C. Solid contaminates 3 are removed fromseparator 21. The produced steam 4 is divided into two flows—portion 5of the produced steam (70%) at a temperature 99.7 C is recycled, usingmechanical compression, an ejector (not shown) or any other means, togenerating the recycle flow. The recycled steam 5 is heated with a 12 kwheat source to generate superheated steam 7 at a temperature of 534 C.The remaining 30% of the produced steam 8 is condensed by direct contactmixture with process water 9 at a temperature of 20 C to generate 80 Cprocess water that can used in the extraction process. The producedsteam 4 can be further cleaned with any dry or wet commerciallyavailable cleaning systems, such as a wet scrubber (not shown) withsaturated water, possibly with additional chemicals to removecontaminates. This cleaning can prevent build-ups at the recycling lowpressure compressing unit and the heating unit 25. A total of 206kg/hour of hot water is generated in this simulation from a 12 kw heatsorce.

Flow Number 1 2 3 4 5 6 T, C. 20.00 99.73 99.73 99.73 99.73 108.00Press., atm 1.00 1.00 1.00 1.00 1.00 1.10 Vapor Fraction 0.00 0.88 0.001.00 1.00 1.00 Enthalpy, kW −132.07 −293.79 −41.37 −248.71 −174.10−173.88 Total Flow, 30.00 78.84 9.00 69.84 48.89 48.89 kg/hr Water,kg/hr 20.10 66.85 0.00 66.85 46.79 46.79 Solids 9.00 9.00 9.00 0.00 0.000.00 N-Butane 0.45 1.50 0.00 1.50 1.05 1.05 N-Pentane 0.32 1.05 0.001.05 0.73 0.73 N-Hexane 0.14 0.45 0.00 0.45 0.31 0.31 Flow Number 7 8 910 11 T, C. 534.94 99.73 20.00 80.11 80.11 Press., atm 1.00 1.00 1.001.00 1.00 Vapor Fraction 1.00 1.00 0.00 1.00 0.00 Enthalpy, kW −161.88−74.61 −821.39 −0.61 −895.39 Total Flow, kg/hr 48.89 20.95 186.00 0.51206.44 Water, kg/hr 46.79 20.05 186.00 0.10 205.95 Solids 0.00 0.00 0.000.00 0.00 N-Butane 1.05 0.45 0.00 0.26 0.18 N-Pentane 0.73 0.31 0.000.12 0.20 N-Hexane 0.31 0.13 0.00 0.03 0.11

Example 11

The following table are the simulation results for the process describedin FIG. 29. The water feed 1 is tailings water from an open mineoilsands extraction facility. The feed water includes 30% solids and 3%solvents at a temperature of 20 C. The system is at a low pressure,close to atmospheric pressure. The produced water 1 is mixed withsuperheated steam 7 at 492 C. Solid contaminates 3 are removed fromseparator 21. The produced steam is condensed by direct contact mixturewith process water 9 at a temperature of 20 C to generate 80 C processwater that can be used in the extraction process. A portion of theproduced water is heated in boiler 25 to generate superheated steam. Theflow to produce the steam 5 can be further treated to removecontaminates to increase its quality to BFW quality water. Anotheroption is to split the produced steam 4, scrub a portion, condense theclean scrubbed steam to water, possibly with water from an exteriorsource, and use the clean condensate to generate the super heated steam7. This option was described in other figures but is not reflected inthe current simulation.

Flow No. 1 2 3 4 5 6 T, C. 20 110.46 110.46 110.46 80.07 80.07 Press.,atm 1 1.00 1.00 1.00 1.00 1.10 Vapor Fraction 0 1.00 0.00 1.00 0.00 0.00Enthalpy, kW −20.31 −68.23 −2.51 −65.72 −59.92 −59.92 Total Flow, 619.80 1.80 18.00 13.80 13.80 kg/hr Water, kg/hr 4.02 17.81 0.00 17.8113.79 13.79 Solids 1.8 1.80 1.80 0.00 0.00 0.00 Hydrocarbons 0.180 0.1940.000 0.194 0.015 0.015 Flow No. 7 8 9 10 11 T, C. 492.40 80.07 20.0080.07 80.07 Press., atm 1.00 1.00 1.00 1.00 1.00 Vapor Fraction 1.000.00 0.00 1.00 0.00 Enthalpy, kW −47.91 −803.20 −737.48 0.00 −743.28Total Flow, kg/hr 13.80 185.00 167.00 0.00 171.20 Water, kg/hr 13.79184.81 167.00 0.00 171.02 Solids 0.00 0.00 0.00 0.00 0.00 Hydrocarbons0.015 0.194 0.000 0.000 0.180

Example 12

The following table is a simulation of the method described in FIG. 3that illustrated producing steam with the use of a heat source withoutusing an external source for the driving steam and with the use of ahigh pressure steam ejector to generate the internal flow in the system.SD-DCSG 30 includes a hot and dry steam injection 36. In the simulation,the driving steam temperature was around 480 C—a typical re-heatertemperature. Low quality produced water 34, at a temperature of 200 Cwith solids and bitumen contaminates, is injected into the steam. Insidethe SD-DCSG the injected liquid water is converted into steam at 280 Ctemperature and is at the same 600 psi pressure as the dry driving steam36. An 80% portion of the generated steam 32 is recycled through theejector. The ejector is only designed to create the steam flow throughheat exchanger 38 and create the flow through the SD-DCSG 30. Highpressure steam 40 at a pressure of 1450 psi and a temperature of 311 Cis injected through ejector to generate the required over pressure andflow in line 36. The produced low pressure steam flows to heat exchanger38 where 12 kw heat is added to the recycled steam flow 32 to generate aheated “dry” steam 36 at 480 C. This steam is used to drive the SD-DCSGas it is injected into the steam generation enclosure 30 and the excessheat energy is used to evaporate the injected water and generateadditional steam 31 at 280 C. The produced steam 31 or just the recycledproduced steam 32 can be cleaned of solids carried with the steam gas byan additional commercially available system (not shown).

Line Number Inside SD- DCSG Ejector 34 30 35 31 32 Discharge 36 33 40 T,C. 200 280.46 280.46 280.46 280.45 279.93 480.69 280.45 311.59 Press.,psig 600 600.00 600.00 600.00 600.00 601.47 600.00 600.00 1450.38 Vapor0 1.00 0.00 1.00 1.00 1.00 1.00 1.00 1.00 Fraction Enthalpy, −92.863−387.97 −4.78 −383.14 −302.80 −306.85 −295.10 −80.49 −4.05 kW TotalFlow, 22.5 108.49 1.22 107.26 84.82 85.92 85.99 22.55 1.10 kg/hr Water,20.925 105.37 0.00 105.37 83.27 84.37 84.44 22.14 1.10 kg/hr Solids1.125 1.13 1.13 0.00 0.00 0.00 0.00 0.00 0.00 Bitumen 0.450 1.995 0.1001.895 1.545 1.545 1.545 0.411 0.000

Example 13

The following table simulates the process as described in FIG. 3 forin-situ oilsands thermal extraction facilities, like SAGD, for 600 psipressures. The water feed is hot produced water at 200 C that includessolids and bitumen. The heat source Q′ for the simulation was 12 KW. Aportion of the heavy hydrocarbons are separated with the solids.

Flow Number 34 35 31 32 36 33 T, C. 200 283.24 283.24 283.08 486.97283.08 Press., psig 600 600.00 600.00 600.00 600.00 600.00 VaporFraction 0 0.00 1.00 1.00 1.00 1.00 Enthalpy, kW −92.863 −4.78 −380.72−304.70 −292.68 −76.17 Total Flow, kg/hr 22.5 1.23 106.83 85.56 85.5621.39 Water, kg/hr 20.925 0.00 104.77 83.85 83.85 20.96 Solids 1.1251.13 0.00 0.00 0.00 0.00 Bitumen 0.450 0.108 2.055 1.713 1.713 0.428

The table and the graph in FIG. 30 show the produce steam amount as afunction of the feed water temperature in the system, as described inexample 13. The simulation shows that with 20 C feed water, 15.1 kg/hrsteam at 600 psi and 280 C will be produced from 12 kw heat source. With240 C produced feed water, 23.5 kg/hr steam at 600 psi and 280 C will beproduced from 12 kw heat source. There is an advantage to using hotproduced water as the heat energy within the produced water: it willincrease the amount of the produced steam. A portion of the hydrocarbonswith the produced water will be converted to gas and flow with theproduced steam.

1. A method for steam production for extraction of oil, said methodcomprising the steps of: generating steam through indirect heatexchange; mixing said steam with liquid water having solids and organicscontaminates, so as to transfer said liquid water from a liquid phase toa gas phase; and removing solids to produce solids free gas phase steam.2. A method for steam production for oil production, said methodcomprising the steps of: generating steam through indirect heatexchange; using the generated steam energy to directly gasify liquidwater with solids and organic contaminated, so as to transfer saidliquid water from a liquid phase to a gas phase; removing solids toproduce solids free gas phase steam; condensing the generate steam togenerate heat and water; and using the generated heat and water for oilproduction.
 3. A system for producing steam for extract heavy bitumen,the system comprising: a heat exchanger means for indirectly heatingwater to generate superheated steam; a steam drive direct contact steamgenerator, mixing steam generated by said heater with water containinglevels of solids therein to form a steam stream and solids dischargedstreams, wherein said steam drive direct contact steam generator is influid connection to said heater; and an enhanced oil recovery facilityin fluid connection to said steam drive direct contact steam generator.4. A system for producing steam for extract oil production bitumen, thesystem comprising: a pressurized longitude mixing chamber means fordirectly mixing steam and water; an internal rotating element within themixing chamber, said rotating element enhancing the mixture between thesteam and the water; and an inlet for steam, an inlet for water, anoutlet for waste and an outlet for steam.
 5. A system for producingsteam for extract oil production bitumen, the system comprising: apressurized longitude mixing chamber means for directly mixing steam andwater; a water inlet located at the upper section of the enclosure; asteam injection inlet located below the water inlet; a produced steamoutlet located above the injection steam inlet; and a waste outletlocated at the lower point of the system.
 6. The method of claim 1,wherein a portion of said generated produced steam is recycled andheated indirectly before being mixed with the said liquid water havingsolids and organics contaminates.
 7. The method of claim 1, wherein saidgenerated superheated steam is generated in a boiler from treated waterflow before mixed with said liquid water having solids and organicscontaminates.
 8. The method of claim 6, further comprising the step of:circulating the portion of the produced steam in a steam ejector,wherein steam for operating said steam ejector is added to the producedsteam.
 9. The method of claim 1, further comprising the step of:injecting the produced steam to recover oil through an oil injectionwell.
 10. The method of claim 8, wherein the feed water is comprised ofhydrocarbons that converted to gas and mixed with the steam.
 11. Themethod of claim 9, further comprising the step of: adding solvents tothe produced steam prior to injecting underground.
 12. The method ofclaim 1, further comprising the step of: scrubbing a portion of theproduced steam by mixing with saturated water and recycling thesaturated water with the scrubbed contaminates back to the step ofmixing the contaminated water with said super heated steam.
 13. Themethod of claim 12, further comprising the step of: adding chemicals tosaid saturated scrubbing water so as to improve scrubbing performance ofcontaminates.
 14. The method of claim 12, further comprising the stepof: using a portion of the scrubbed steam as recycle fluid through anheater to generate said superheated steam.
 15. The method of claim 2,further comprising the step of: separating non-condensable gases, havinghydrocarbons and solvent remains, from the condensed hot water; andcombusting said non-condensable gases generating said superheated steam.16. The method of claim 1, further comprising the steps of: producingoil and water from a production well; separating portion of the waterfrom hydrocarbons, solvents, and solids contaminates; and mixing saidproduced water with said superheated steam.
 17. The system of claim 3,further comprising: a production well producing a mixture of water, oiland gas; a separator fluidly connected to the production well forreparations portion of the produce water from the oil, being fluidlyconnected to said direct contact steam generator; and a heater forgenerating said superheated driving steam.
 18. The system of claim 17,further comprising: a high pressure steam supply to an ejector; and anejector means for recycling portion of said produced steam from saiddirect contact steam generator to said heater to generate said drivingsuperheated driving steam.
 19. The system of claim 17, wherein saiddirect contact steam generator and said heater are located on a well padin proximity to the steam injection well.